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Port Said University Faculty of Engineering Natural Gas Engineering Program

A study on:Belayim Marine Field ( Zone II)

Submitted to:Natural Gas Engineering Program

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ACKNOWLEDGMENT

ACKNOWLEDGMENT Thanks and indebtedness is directed first and always to Allah for all his graces, without the power he gave to us , the accomplishment of this work would have been certainly impossible. We would like to extend our deep gratitude and appreciation to our family; for their love, help, understanding and continuous encouragement. We would like to express our deep gratitude, appreciation and sincerest thanks to our professor for his supervision, advices, constructive discussion and great help during the work Professor Doctor Attia M. Attia, our thesis supervisor. Finally, we would like to express our gratitude to our project assistant Eng. Ahmed Rayan who helped us technically and mentally throughout our work period.

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Contents

Contents CHAPTER 1 ...................................................................................................................... 1 1.1 Introduction .......................................................................................................................................... 1 Belayim Marine Field (ZoneII) ........................................................................................................ 1 1.2 Objectives ................................................................................................................................................ 4

CHAPTER 2 ...................................................................................................................... 5 2 Literature Review................................................................................................................................... 5 2.1 Reserves Definition .................................................................................................................... 5 2.1.1 SEC Definitions ............................................................................................................... 6 2.1.2 SPE Definitio n s ......................................................................................................... 9 2 . 2 R e s e r v e E s t i m a t i o n M e t h o d s .................................................................................... 12 2.2.1 Analogy:- ...................................................................................................................... 13 2.2.2 Volumetric Method ....................................................................................................... 15 2.2.2.1 Volumetric Uncertainty ....................................................................................... 17 2.2.3 Decline Curve Analysis (DCA): ............................................................................... 18 2.2.4 Material Balance Equation (MBE): .............................................................................. 24 2.2.4.1 MBE Assumptions:............................................................................................. 27 2.2.4.2 Primary Recovery Mechanism ............................................................................. 29 2.2.4.2 .1Rock And Liquid Expansion Drive: ....................................................... 30 2.2.4.2 .2 Depletion Drive: ......................................................................................... 31 2.2.4.2 .3 Gas-Cap Drive: .......................................................................................... 33 2.2.4.2.4 .Water Drive: ............................................................................................. 35 2.2.4.2.5 Gravity Drainage Drive : ............................................................................. 37 2.2.4.2.6 Combination: ............................................................................................. 39 2.2.4.3 Driving Indexes MBE: ........................................................................................ 40 2.2.4.3.1 Depletion Drive Index(Oil Zone Oil Expansion ),(DDI) ...................... 41 2.2.4.3.2Segregation Drive Index (Gas Zone Gas Expansion),(SDI) .................... 41 2.2.4.3.3Water Drive Index (W DI) .......................................................................... 41 2.2.4.3.4Expansion Drive Index (Rock And Liquid), (EDI) .............................. 41 2.2.4.4 MBE In Linear Form: .......................................................................................... 42 2.2.4.4.1 Volumetric Under saturated Reservoir ........................................................ 45 2.2.4.4 .2Volumetric Saturated Reservoirs ........................................................... 47 2.2.4.4 .3 Gas Cap Drive Reservoirs ...................................................................... 48 2.2.4.4 .4 Water Drive Reservoirs ............................................................................ 50 2.2.4.4 .5 Combination Drive Reservoir ............................................................... 57 2.2.4.5 Water Influx[5] .................................................................................................... 59 2.2.4.5 .1 Steady-state method .................................................................................... 59 2.2.4.5.2 VEH unsteady-state method ........................................................................ 61 2.2.4.5.3 Fetkovich Pseudo steady-state method ...................................................... 63 2.3 Enhanced Oil Recovery (EOR) [16,17] ................................................................................... 65 2.3 .1 Miscible EOR ................................................................................................................ 65 iv

Contents

2.3 .2 Chemical EOR ............................................................................................................. 66 2.3.3 Other EOR Processes ................................................................................................... 66 2.3 .2.1 Polymer Flooding ................................................................................................ 69 2.3.2.2 Surfactant Flooding ............................................................................................. 74 2.3 .2.3 Alkaline Flooding ............................................................................................... 75 2.4 Reservoir Simulation ......................................................................................................... 80 2.4.1 MBAL [22] .................................................................................................................... 81 2.4.2 Monte Carlo Simulation .............................................................................................. 83 2.4.3 ECLIPSE Simulation[21] .............................................................................................. 84 2.5 Comparison Between Reserve Estimation Methods[23] .......................................................... 87

CHAPTER 3 .................................................................................................................... 89 3 Methodology..............................................................................................................................................89 3.1 Available Data .......................................................................................................................... 89 3.2 Methodology............................................................................................................................. 92 3.2.1.1 The Material Balance Equation ............................................................................ 93 3.2.1.2 Water Influx ....................................................................................................... 101 3.2.1.2 .1Steady state Water Influx (SS) ................................................................... 101 3.2.1.2 .2 Semi-Steady State For Water Influx (SSS) ............................................... 105 3.2.1.2 .3 Unsteady state (USS) ................................................................................ 110 3.2.1.3 Prediction ........................................................................................................... 116 3.2.2 Reservoir Management Spread sheet ........................................................................... 125 3.2.3MBAL [24] ................................................................................................................... 129 3.2.3.1 Montecarlo Simulation Tool [24] : .................................................................... 129 3.2.3.2 MBE Tool [24] : ................................................................................................ 133 3.2.4 ECLIPSE [21] .............................................................................................................. 149

CHAPTER4 ................................................................................................................... 160 4

Result ..................................................................................................................................................160 4.1PVT Correlations [5] ............................................................................................................... 160 4.2 History Matching .................................................................................................................... 167 4.3 Prediction................................................................................................................................ 172 4.4EOR ......................................................................................................................................... 175 4.5 MBAL .................................................................................................................................... 178 4.6 ECLIPSE Results .................................................................................................................... 179 Conclusion .................................................................................................................................... 189 REFERENCES ............................................................................................................................. 191

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List of Figures

List of Figures Figure 1 Belayim Marine Oil Location Map . ........................................................................................................... 2 Figure 2 SEC Classification Of Oil And Gas Resources .[2] .................................................................................... 6 Figure 3 SPE Resource Classification System[1] ...................................................................................................... 9 Figure 4 Probabilistic Definition Of Reserves. ........................................................................................................ 10 Figure 5 Classification of production decline curves .[4] ........................................................................................ 19 Figure 6 Exponential, Hyperbolic And Harmonic Approaches . ............................................................................. 22 Figure 7 Decline Curve of an Oil well . [6] ............................................................................................................. 23 Figure 8 (Material Balance Tank Model) ................................................................................................................ 24 Figure 9 Solution Gas Drive Reservoir.[8] .............................................................................................................. 31 Figure 10 Production Data Of Depletion Drive Reservoir. [8] ............................................................................... 32 Figure 11 Gas-cap drive reservoir.[8] ..................................................................................................................... 33 Figure 12 Production Data For A Gas-Cap Drive Reservoir.[8] ............................................................................ 34 Figure 13 Reservoir With Water Drive .[8] ............................................................................................................. 35 Figure 14 Aquifer Geometries . [8].......................................................................................................................... 36 Figure 15 Production Data For A Water Drive Reservoir. [8] ............................................................................... 36 Figure 16 Initial Fluid Distribution In An Oil Reservoir . [8] ................................................................................. 37 Figure 17 Combination Drive Mechanism . [8] ....................................................................................................... 39 Figure 18 Classification Of The Reservoir. [5] ....................................................................................................... 46 Figure 19 Determining N For Saturated Reservoirs . [5] ........................................................................................ 47 Figure 20 F versus Eo + m Eg . [5] ........................................................................................................................ 49 Figure 21(F/Eo) versus (Eg/Eo)............................................................................................................................... 49 Figure 22 (F/Eo) As A Function Of (∆P/Eo) .[5] ..................................................................................................... 52 Figure 23 Steady State Model Applied To MBE.[5] ................................................................................................. 53 Figure 24 Havlena And Odeh Straight Line Plot . [10.11] ....................................................................................... 56 Figure 25 VEH Cylindrical In Shape Reservoir....................................................................................................... 61 Figure 26 Dimensionless Time And Fluid Influx Chart.[5] ..................................................................................... 62 Figure 27 Pressure Steps Used To Approximate The Pressure-Time Curve . [5] .................................................... 63 Figure 28 EOR Injection Method.[17] ..................................................................................................................... 67 Figure 29 Chemical EOR Target In Selected Countries.[17] .................................................................................. 68 Figure 30 Chemical Floods History. [17]................................................................................................................ 68 Figure 31 Current Status World Wide Production World Wide.[17] ....................................................................... 68 Figure 32 Polymer Flood Field Performance .[17] ................................................................................................. 73 Figure 33 Surfactant Flood [17] .............................................................................................................................. 74 Figure 34 pH Values Of Alkaline Solutions .[16] .................................................................................................... 76 Figure 35 Alkaline Flood Field Performance. [17] ................................................................................................. 78 Figure 36 Isopach Contour Map For Net Pay Zone OF Marine Zone 2 . ............................................................... 89 Figure 37 Reservoir MBE . ...................................................................................................................................... 94 Figure 38 Chart Calculate N. ................................................................................................................................ 100 Figure 39 Plot Of Pressure And Pressure Drop Versus Time. [15] ....................................................................... 101 Figure 40 Semi Steady State Behavior . ................................................................................................................ 105 Figure 41 Un Steady State Behavior ..................................................................................................................... 110 Figure 42 Plotting ∑Qt.∆P/Eo Vs (F-Wi*Βw)/EO At Re/Rw =2. .......................................................................... 113 Figure 43 Plotting ∑Qt.∆P/Eo vs (F-Wi*βw)/EO at re/rw =4............................................................................... 113 Figure 44 Plotting ∑Qt.∆P/Eo vs (F-Wi*βw)/EO at re/rw =8............................................................................... 114 Figure 45 Plotting ∑Qt.∆P/Eo vs (F-Wi*βw)/EO at re/rw =6............................................................................... 114 Figure 46 ∑Qt.∆P/Eo At Re/Rw = Infinity............................................................................................................. 115 Figure 47 Chart between P with ( wepe& we uss)) ................................................................................................ 123 Figure 48 Chart Between P With ( Wepe& We Uss)By Using Mew Wi. ................................................................ 124 Figure 49 Predicted p . .......................................................................................................................................... 124 Figure 50 Reservoir Management Spread Sheet Wells Input. ................................................................................ 125

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List of Figures

Figure 51Reservoir Management Spread Sheet Pressure Input. ........................................................................... 126 Figure 52 Pressure Matching ................................................................................................................................ 126 Figure 53 Reservoir Management Spread Sheet PVT Input . ................................................................................ 126 Figure 54 Reservoir management spread sheet PVT Matching . ......................................................................... 127 Figure 55 Reservoir Management Spread Sheet Well Locations. .......................................................................... 127 Figure 56 Reservoir Management Spread Sheet Prediction .................................................................................. 128 Figure 57 Reservoir Management Spread Sheet Prediction by chemical effect ..................................................... 128 Figure 58 Choosing Monte Carlo Tool. ................................................................................................................. 129 Figure 59 System Option Window.......................................................................................................................... 130 Figure 60 PVT Menu ............................................................................................................................................. 130 Figure 61 Data Input ............................................................................................................................................. 130 Figure 62 Match PVT data .................................................................................................................................... 131 Figure 63 Selecting Distributions. ......................................................................................................................... 131 Figure 64 Distributions.......................................................................................................................................... 132 Figure 65 General Option Widow. ........................................................................................................................ 134 Figure 66 PVT list ................................................................................................................................................ 135 Figure 67 Black Oil ( Data Input). ......................................................................................................................... 135 Figure 68 PVT Matching. ...................................................................................................................................... 136 Figure 69 Matching. .............................................................................................................................................. 136 Figure 70 Oil FVF Curve...................................................................................................................................... 137 Figure 71 Oil Viscosity Curve............................................................................................................................... 137 Figure 72 GOR Curve. .......................................................................................................................................... 138 Figure 73 Input List. ............................................................................................................................................. 138 Figure 74 Tank Parameters. .................................................................................................................................. 139 Figure 75 Water Influx.......................................................................................................................................... 139 Figure 76 Rock Compressibility............................................................................................................................. 140 Figure 77 Rock Compaction. ................................................................................................................................. 140 Figure 78 Relative Permeability. ........................................................................................................................... 141 Figure 79 Relative Permeability Curves. ............................................................................................................... 141 Figure 80 History Matching Table......................................................................................................................... 142 Figure 81 Import Window. .................................................................................................................................... 142 Figure 82 Import Setup. ........................................................................................................................................ 143 Figure 83 Import file. ............................................................................................................................................. 143 Figure 84 History Matching List........................................................................................................................... 144 Figure 85 Run History Matching. .......................................................................................................................... 144 Figure 86 Analytical Method. ............................................................................................................................... 145 Figure 87 Graphical method.................................................................................................................................. 145 Figure 88 Energy Plot........................................................................................................................................... 146 Figure 89 WD Function Plot.................................................................................................................................. 146 Figure 90 Production Prediction List. ................................................................................................................... 147 Figure 91 Prediction Calculation Setup. ............................................................................................................... 147 Figure 92 Tank Prediction Data. ........................................................................................................................... 148 Figure 93 Run Simulation Window. ....................................................................................................................... 148 Figure 94 Data File Section. .................................................................................................................................. 149 Figure 95 Simulator Preface.................................................................................................................................. 153 Figure 96 Run The Simulator................................................................................................................................. 153 Figure 97 Running The Simulator. ........................................................................................................................ 153 Figure 98 Print File Location. ............................................................................................................................... 154 Figure 99 Original Oil In Place (OOIP)................................................................................................................ 154 Figure 100 Start FLOVIZ ...................................................................................................................................... 154 Figure 101 Run The Model 1 . .............................................................................................................................. 155 Figure 102 Run The Model 3 . .............................................................................................................................. 155 Figure 103 Run The Model 2. ................................................................................................................................ 155 Figure 104 (FLOVIZ Parameters). ........................................................................................................................ 156 Figure 105 Reservoir Model . ............................................................................................................................... 156 Figure 106 RUN OFFICE...................................................................................................................................... 157

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List of Figures

Figure 107 Load All Vectors . ................................................................................................................................ 157 Figure 108 Input Variables . .................................................................................................................................. 158 Figure 109 Output OFFICE. ................................................................................................................................. 158 Figure 110 OFFICE Output table.......................................................................................................................... 159 Figure 111 OFFICE Output Charts . .................................................................................................................... 159 Figure 112 Gas Solubility ...................................................................................................................................... 160 Figure 113 Correction..................................................................................................................................... 161 Figure 114 FVF ..................................................................................................................................................... 162 Figure 115 Oil Compressibility ............................................................................................................................. 163 Figure 116 Oil Viscosity ........................................................................................................................................ 164 Figure 117 Crude Oil Denisty................................................................................................................................ 165 Figure 118 Bw ....................................................................................................................................................... 165 Figure 119 Water Compressibility ......................................................................................................................... 166 Figure 121 Gp Vs Years ......................................................................................................................................... 168 Figure 120 Wp,Wi,Np (bbl) Vs Years ..................................................................................................................... 168 Figure 122 Cw,Co,Rs ............................................................................................................................................. 170 Figure 123 Bo, Mo ................................................................................................................................................. 170 Figure 124 re/rw=infinty ....................................................................................................................................... 171 Figure 125 Past& Future....................................................................................................................................... 174 Figure 126Purely Viscous...................................................................................................................................... 175 Figure 127 Visco Elastic ........................................................................................................................................ 176 Figure 128 prediction by chemical effect ............................................................................................................... 177 Figure 129 Montecarlo Results 2 ........................................................................................................................... 178 Figure 130 Montecarlo Results 1 ........................................................................................................................... 178 Figure 131 Drive mechanism ................................................................................................................................. 179 Figure 132 Bottom drive aquifer............................................................................................................................ 179 Figure 133 graphical method................................................................................................................................. 180 Figure 134 Analytical method ................................................................................................................................ 180 Figure 135 Gas and oil rate ................................................................................................................................... 181 Figure 136 Average water injected with cumulative oil produced ......................................................................... 181 Figure 137 cumulative gas and oil produced ......................................................................................................... 182 Figure 138 Cumulative oil produced with water injected ...................................................................................... 182 Figure 139 water injection And cumulative oil production with time .................................................................... 183 Figure 140 oil saturation with time........................................................................................................................ 183 Figure 141 recovery factor .................................................................................................................................... 184 Figure 142 Reservoir Model .................................................................................................................................. 185 Figure 143 Side view ............................................................................................................................................. 185 Figure 144 FOPT,FGPT, FWPT, FWIT Vs Date ................................................................................................... 186 Figure 145FGPR, FOPR, FWPR, FWIR Vs Date .................................................................................................. 186 Figure 146 In place calculation ............................................................................................................................. 187 Figure 147 New Well ............................................................................................................................................. 188 Figure 148 Comparison no. of wells ...................................................................................................................... 188 Figure 149 Comparison Inj. Wells ......................................................................................................................... 189

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LIST OF TABLES

List Of Tables Table 1 Classification Of Proved Reserves.[2] .......................................................................................................... 8 Table 2 Historical Development Of Reserves Definitions And Classifications. ........................................................ 11 Table 3 Recovery Factors For Oil And Gas Reservoirs .[2] .................................................................................... 16 Table 4 Decline Curve Equations'. ......................................................................................................................... 21 Table 5 Dimensionless Time And Fluid Influx Table .[5] ........................................................................................ 62 Table 6 Polymer Structures And Their Characteristics.[16] ................................................................................... 70 Table 7 Properties Of Several Common Alkalis .[16].............................................................................................. 77 Table 8 Reserve Estimation Methods Comparison .[23] ......................................................................................... 87 Table 9 Summary Of Reserve Estimation Methods.[23] .......................................................................................... 88 Table 10 Belayim Marine Field (Zone 2) Data........................................................................................................ 90 Table 11 Belayim Marine Field (Zone 2) Pvt Data . ............................................................................................... 91 Table 12 Calculate Oil Compressibility. .................................................................................................................. 96 Table 13 Calculate Water Compressibility . ............................................................................................................ 97 Table 14 Calculate Effective Compressibility. ........................................................................................................ 98 Table 15 Calculate Wi ,Wp,βw . ............................................................................................................................... 98 Table 16 Calculate (Eo)&(F-Wi βw). ...................................................................................................................... 99 Table 17 Marine zone II Data ................................................................................................................................ 103 Table 18 Calculated k' values ................................................................................................................................ 104 Table 19 Determining Semi Steady State Equations’ Parameters ......................................................................... 108 Table 20 Comparing Values Of (Δwe SSS)/ΔT And (Δwe MBE)/ΔT. .................................................................. 109 Table 21 Td vs pressure and Ce. ............................................................................................................................ 112 Table 22 Calculation of ∑Qt.∆P/Eo at re/rw = 2 and 4. ....................................................................................... 113 Table 23 Calculation Of ∑Qt.∆P/Eo At Re/Rw = 6 And 8. .................................................................................... 114 Table 24 Calculating ∑Qt.∆P/Eo At Re/Rw = Infinity. .......................................................................................... 115 Table 25 Prediction Table ..................................................................................................................................... 116 Table 26 3 Pressures Assumption .......................................................................................................................... 116 Table 27 Cw,Co,Ce, βo, βw for P.=1400 ............................................................................................................... 116 Table 28 Cw,Co,Ce, βo, βw for P.=1410 ............................................................................................................... 117 Table 29 Cw,Co,Ce, βo, βw for P.=1420 ............................................................................................................... 117 Table 30 Input Cw,Co,Ce, βo, βw for the 3 P. ....................................................................................................... 117 Table 31Calculate Delta P..................................................................................................................................... 118 Table 32 Calculate TD ........................................................................................................................................... 118 Table 33 Calculate TD at re/rw >10 [5]................................................................................................................ 119 Table 34 Calculate (QT) ........................................................................................................................................ 119 Table 35 Calculate ∑Qt.∆P ................................................................................................................................... 120 Table 36 Input QT ,∑Qt.∆P. .................................................................................................................................. 120 Table 37 Calculate We uss ..................................................................................................................................... 121 Table 38 Input Wp ,NP........................................................................................................................................... 121 Table 39 Calculate Wi ........................................................................................................................................... 122 Table 40 Calculate NP*βo ,WP*βw, WI*βw ,∆P ................................................................................................... 122 Table 41 Calculate N*βoi*Ce*∆P ......................................................................................................................... 122 Table 42 Calculate We MBE .................................................................................................................................. 123 Table 43 crude oil denisty used correletion. .......................................................................................................... 164 Table 44 Oil Denisty suitable Correlation ............................................................................................................. 164 Table 45 PVT Conculosion .................................................................................................................................... 166 Table 46 History Matching. ................................................................................................................................... 167 Table 47 PVT Matching. ........................................................................................................................................ 169 Table 48 Wi/Np & dWi/Np ..................................................................................................................................... 172 Table 49 Prediction Calculation ............................................................................................................................ 173 Table 50 Conclusion .............................................................................................................................................. 190

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LIST OF TABLES

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CHAPTER 1

CHAPTER 1 1.1 Introduction Belayim Marine Field (ZoneII) Zone II is one of the oil reservoirs composing Belayim Marine field; from the stratigraphic point of view, it belongs to the upper portion of Belayim formation. Zone II was discovered by 113M-1 in 1962 and production started in 1963 through wells 113M-1 & BM2, by Dec. 1996, Zone II had produced a cum. of 6.75*106 STD m3 of oil and the production rate was 526 STD m3/d. The geological structure of Zone II that was reconstructed based composed of sand bodies mainly deposited in the west-southwest flank of an anticline with a north-west southeast trend. The sand thickness reduces along the crest of the structure and is interrupted by a fault along the west flank. Two aquifers have been identified based on the different original OWC depths. The OWC of the main aquifer is identified based on the log analysis of well 113M-25, the secondary aquifer is present only in an isolated area and well 113M-31 identified it. The oil characteristics were determined based on the analysis of the surface sample collected at well 113M-26; it points out a mediumhigh density oil of 20.7 API.

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CHAPTER 1

Balayim Marine Oil Field – Location map

CHAPTER 1

Figure 1 Belayim Marine Oil Location Map .

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CHAPTER 1

This book starts with showing the project objectives to be a good reservoir engineer and whats the purpose of reservoir engineering and what is reservoir engineer concerns. Then talking about literature review about reservoir engineering which used to build knowledge about types of reservoirs, driving mechanisms and different types of reserve calculation. Then starts to show the available data that will be used in calculations and starts it in methodology that shows the procedures followed in calculation to get final results Finally the book shows the final results and conclusion of different calculations type and compare between results to get the best one and build recommendations to increasing the recovery factor and productivity

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CHAPTER 1

1.2 Objectives From Reservoir Engineering Concepts Starting The Main Project Objectives:1- Selecting the most suitable correlations to calculate fluid properties of (Belayim Marine Field (ZoneII)) with lowest

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average absolute error(AAE) to helping and decrease money paid in core analysis and PVT Lab. Knowing the reservoir type and its driving mechanism. Calculating the original oil in place (OOIP) by using different methods e.g.(MBE, Montecarlo , Decline curve, MBAL ,Eclipse) , compare between those methods and choose the most accurate result. Predicting of the reservoir life and production rate with highest recovery factor. Enhancing oil recovery method to increase oil production and decrease water cut percentage.

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CHAPTER 2 2 Literature Review 2.1 Reserves Definition Unfortunately, there are some disagreements in the world related to reserve definition. While some countries base their reserves on maximum recoverable, others rely on minimum recoverable. Many countries tend to maximize their reserves for political and economic reasons and keep their reserves confidential. So it is very difficult to estimate the world reserves, not only for the disagreements in definitions but also for the lack of data and incorrect aggregation. The problem of definitions is being solved over the years by applying standard definitions. The most common definitions used globally are those set by SPE and The US Securities and Exchange Commission (SEC).

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2.1.1 SEC Definitions According to the US Securities and Exchange Commission (SEC), Oil and Gas resources are classified according to the flow chart shown in Figure

Figure 2 SEC Classification Of Oil And Gas Resources .[2]

The total oil and gas resources are the total quantities expected to be present underground, this can be divided into discovered resources and undiscovered resources. Undiscovered resources are those quantities not yet discovered. Discovered resources are those resources already discovered using existing technology. They can be classified into recoverable and unrecoverable resources. Unrecoverable resources are those quantities that cannot be recovered due to lack of technology or economic reasons. Recoverable resources are those quantities that can be recovered using existing technology and current economic conditions. They can be further classified into reserves and cumulative production.

Cumulative production is the quantities already produced from known accumulation s using the existing technology and under current economic conditions. 6

Reserves are estimated volumes of crude oil, condensate, natural gas, natural gas liquids, and associated substances anticipated to be commercially recoverable from known accumulations from a given date forward, under existing economic conditions, by established operating practices, and under current government regulations. Reserve estimates are based on geologic and/or engineering data available at the time of estimate. The relative degree of an estimated uncertainty is reflected by the categorization of reserves as either "proved" or "unproved" Proved Reserves can be estimated with reasonable certainty to be recoverable under current economic conditions. Current economic conditions include prices and costs prevailing at the time of the estimate. Reserves are considered proved if the commercial productivity of the reservoir is supported by actual engineering tests. By using probabilistic approach, if the probability that the real production will have a chance of 90% to exceed or be equal to the calculated value, we consider the estimated value as proved reserves. Proved reserves can be further classified as shown in Figure 2. Unproved Reserves are based on geological and/or engineering data similar to those used in the estimates of proved reserves, but when technical, contractual, economic or regulatory uncertainties preclude such reserves being classified as proved. They may be estimated assuming future economic conditions different from those prevailing at the time of the estimate.. Unproved reserves may further be classified as probable and possible.

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Probable Reserves (P50) are less certain than proved reserves and can be estimated with a degree of certainty sufficient to indicate they are more likely to be recovered than not. By using probabilistic approach, the chance of the real production figure to be equal to or exceed the calculated value is 50%, we usually refer to it as proved plus probable reserves and are given by (P50). Possible Reserves are less certain than proved reserves and can be estimated with a low degree of certainty, insufficient to indicate whether they are more likely to be recovered than not Table 1 Classification Of Proved Reserves.[2]

PDP are those quantities expected to be recovered from locations where a proper field development plan was introduced, wells were drilled, and production is on-going. PDNP are those quantities expected to be recovere3d from locations where a proper field development plan was introduced, wells were drilled, but production has not yet started. PUD are those quantities that in order to be recovered, the accumulation sin which they exist need a proper development plan to take place in order to decide the number of wells needed And other requirement for these quantities to be produced and the field to be productive.

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2.1.2 SPE Definitions Figure 4 presents the petroleum resource classification according to Society of Petroleum Engineers (SPE) and its similarity to the SEC resource classification

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Figure 3 SPE Resource Classification System[1]

Discovered Petroleum-initially-in-place is that quantity of petroleum which is estimated, on a given date, to be contained in known accumulations, plus those quantities already produced therefrom. This may be may be subdivided into Commercial and Sub-commercial categories, with the estimated potentially recoverable portion being classified as Reserves and Contingent Resources respectively. Reserves are defined as those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. The uncertainty in reserve estimation can be reflected in proved. Probable, and possible reserves. Proved, probable and possible reserves have the same definitions of the SEC classification. The probabilistic approach is best explained in figure 4. 9

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Figure 4 Probabilistic Definition Of Reserves.

Contingent Resources are those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from known accumulations, but which are not currently considered to be commercially recoverable. Undiscovered Petroleum-initially-in-place is that quantity of petroleum which is estimated, on a given date, to be contained in accumulations yet to be discovered. Prospective Resources are those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from undiscovered accumulations Many governments, organisations and companies have made their own reserves definitions and classifications. The complete historical development of reserves definitions and classifications is shown in table 2.

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Table 2 Historical Development Of Reserves Definitions And Classifications. Society of Petroleum Engineers (SPE) Date 1964

Other Organizations

Definition SPE Reserves Definitions [20]

Organization Name

Date

American Petroleum

1936

Institute Reserves Definition (API) [27] 1981

SPE, WPC, AAPG [21]

ARPS Reserve

1962

Classification [28] October, 1988

SPE Reserves Definitions [22]

McKelvey Resource

1972

Classification System [29] March, 1997

SPE/ WPC [23]

SEC Reserve

1975

Classification [30] February,

SPE/WPC/AAPG [24]

Norwegian Petroleum Directorate (NPD) [31]

2000 2001

Guidelines for the Evaluation

The UNFC

of Petroleum Reserves and

Classification System

Resources, 2001 2005

[25]

2001

November 2003

[32]

Glossary of Terms Used in Petroleum Reserves/Resources Definitions [26]

Chinese Classification System [33]

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2005

2 . 2 Reserve Estimation Methods Reserves can be calculated using the following techniques[2] :Analogy Volumetric Decline curve analysis Material Balance Reservoir simulation Two calculation approaches can be applied. These are deterministic and probabilistic approaches. The deterministic approach involves using a single value from each input parameter of the equation used in the estimation process. This generates a single value for the IOIP. This approach is used when uncertainty is low or when the degree of confidence in the data available is very high. The probabilistic approach involves making a probability distribution function for each input parameter using the range of uncertainty in each parameter (minimum, maximum, average). This distribution function allows the calculation of all the possible outcomes of the IOIP value and covers all the ranges of uncertainty. This approach I used when the uncertainty is very high and can be also used as a risk analysis method.

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2.2.1 Analogy:Reserves are estimated by analogy to reservoir in the same geographic area or field with similar properties. The SEC institute that only offset wells in the same field can be used to estimate proved reserves by analogy. Nevertheless, analogy is most used to determine probable and possible reserves in the same geographic area. The similarities between the target reservoir and the analogy model should include :• Lithology and depositional environment of the reservoir rock • Petrophysical parameters of the rock and fluid saturations • Initial bottom hole pressure (BHP) and temperature (BHT) • BHP at the start-up of a project • Reservoir fluid properties (PVT) • Structural configuration • Reservoir heterogeneity and continuity • Recovery mechanism, natural or induced • Well spacing and spacing pattern

Reservoir maturity and the stage of development of both the analogy and the target reservoir should be taken into account. When the proper analogy has been established, it can be used to estimate[2]: • Ultimate recovery per well • Drainage area and appropriate well spacing • Initial reservoir parameters • Initial productivity per well • Typical decline type and decline characteristics • Expected abandonment pressure • Expected drive mechanism 13

• Enhanced recovery factor for pressure maintenance • Recovery for a given drive mechanism: − Per well − Per acre-foot (RF) The analogy method is applied by comparing the following factors for the analogous and current fields or wells: 1. Recovery Factor (RF), 2. Barrels per Acre-Foot (BAF). 3. Estimated Ultimate Recovery (EUR). The RF of a close-to-abandonment analogous field is taken as an approximate value for another field. Similarly, the BAF is assumed to be the same for the analogous and current field or well, which is calculated by the following equation

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2.2.2 Volumetric Method The volumetric technique is the most widely used approach to estimate reserves during the exploration stage of a field. Often used as first step, it is compared with other techniques as more data become available and the uncertainty decrease. The estimate ultimate recovery (EUR) for an oil reservoir is given by:

Where:N = oil in place (STB) RF = Recovery factor Vb = Bulk reservoir volume (acre ft) Ø = Average reservoir porosity Sw = Average reservoir water saturation Bo = Oil formation volume factor (RB/STB)

From a contour map:

where Vb = contour interval Ao = area of the contour Using reservoir drainage area and thickness:-

Where: A = reservoir area (acres) h = thickness (ft)

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Table 3 (gives the typical primary recovery factors for oil and gas reservoirs by drive mechanism. The primary oil driving mechanisms will be discussed in the Material balance equation section .

Table 3 Recovery Factors For Oil And Gas Reservoirs .[2]

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2.2.2.1 Volumetric Uncertainty A volumetric estimate provides a static measure of oil or gas in place. The accuracy of the estimate depends on the amount of data available, which is very limited in the early stages of exploration and increases as wells are drilled and the pool is developed. Monte Carlo simulation provides a methodology to quantify the uncertainty in the volumetric estimate based on assessing the uncertainty in input parameters such as: • Gross rock volume, reservoir geometry and trapping • Pore volume and permeability distribution • Fluid contacts

The accuracy of the reserve or resource estimates also increases once production data is obtained and performance type methods such as material balance and decline analysis can be utilized. Finally, integrating all the techniques provides more reliable answers than relying solely on any one method

17

2.2.3 Decline Curve Analysis (DCA): Production decline analysis is a basic tool for forecasting production from a well or a group of wells once there is sufficient production to establish a decline trend as a function of time or cumulative production. The technique is more accurate than volumetric methods when sufficient data is available to establish a reliable trend and is applicable to both oil and gas wells. It is most often used to estimate remaining recoverable reserves, but it is also useful for water flood and enhanced oil recovery (EOR) performance assessments and in identifying production issues/mechanical problems. Production decline analysis of an analogous producing pool provides a basis for forecasting production and ultimate recovery from an exploration prospect or stepout drilling location. A well‘s production capability declines as production proceeds. This happens mainly due to combination of pressure depletion, displacement of another fluid (gas and/or water) and changes in relative fluid permeability. Plots of production rate versus production history (time or cumulative production) illustrate declining production rates as cumulative production increases. In theory, production decline analysis is only applicable to individual wells but in practice extrapolations of group production trends often provide acceptable approximations for group performance. The estimated ultimate recovery (EUR) for a producing unit is obtained by extrapolating the trend to an economic production limit. The extrapolation is valid provided that [3]: • Past trends were developed with the well producing at capacity. • Volumetric expansion was the primary drive mechanism. The technique is not valid when there is significant pressure support from an underlying aquifer. • The drive mechanism and operating practices continue into the future.

18

Curves that can be used for production forecasting include: 1. Production rate versus time. 2. Production rate versus cumulative production. 3. Water cut percentage versus cumulative production 4. Water level versus cumulative production 5. Cumulative gas versus cumulative oil 6. Pressure versus cumulative production.

Figure 5 shows the classification of production decline curves and how each of them can be applied by using exponential, hyperbolic and harmonic approaches.[4]

Figure 5 Classification of production decline curves .[4]

19

The first two types are the most common types of decline curves, because the trend for wells producing from conventional reservoirs under primary production will be ―exponential‖ ,which means that the data will present a straight line trend when production rate vs. time is plotted on a semi-logarithmic scale. The data will also present a straight line trend when production rate versus cumulative production is plotted on regular Cartesian coordinates. The well‘s ultimate production volume can be read directly from the plot by extrapolating the straight line trend to the production rate economic limit. Arps (1945, 1956) developed the initial series of decline curve equations to model well performance [3]. The equations were initially considered as empirical and were classified into (Exponential, Hyperbolic, Harmonic), based on the value of the exponent ―b‖ that characterizes the change in production decline rate with the rate of production. For exponential decline ‗b‘=0, for hyperbolic ‗b‘ is generally between 0 and 1. Harmonic decline is a special case of hyperbolic decline where ‗b‘=1. Table 4 summarizes ARPS‘ equation used in DCA.

20

Table 4 Decline Curve Equations'.

Figure 6 shows the difference between the exponential, hyperbolic, and harmonic approaches used in DCA (rate versus time). [5]

21

Figure 6 Exponential, Hyperbolic And Harmonic Approaches .

22

Chapter 2

Figure7 is an example of a typical oil well showing the difference between Exponential and Harmonic Extrapolations (rate versus cumulative production) and also shows the economic limit at which data are extrapolated. [6]

Figure 7 Decline Curve of an Oil well . [6]

In Figure 7, the Exponential extrapolation yields a straight line, while the Harmonic extrapolation yielded a concave upward shape (curve). This is due to the difference in the exponent ‗b‘ values for both methods. The economic limit line is the line showing the economic production limit at which the data are extrapolated in order to predict future production.

23

Chapter 2

2.2.4 Material Balance Equation (MBE): Material balance is the technique that uses the law of conservation of matter. The material balance method is a tank model equation. It is written from start of production to any time (t) as the expansion of oil in the oil zone plus the expansion of gas in the gas zone plus the expansion of connate water in the oil and gas zones plus the contraction of pore volume in the oil and gas zones plus the water influx plus the water injected plus the gas injected equal to the oil produced plus the gas produced plus the water produced.[5] Figure 8 shows the tank model on which MBE was built.

Figure 8 (Material Balance Tank Model)

A general material balance equation that can be applied to all reservoir types was first developed by Schilthuis in 1936 [7]. Although it is a tank model equation, it can provide great insight for the practicing reservoir Engineer.

24

Chapter 2

It is written from start of production to any time (t) as follows: Expansion of oil in the oil zone + Expansion of gas in the gas zone + Expansion of connate water in the oil and gas zones + Water influx + Water injected + Gas injected = Oil produced + Gas produced + Water produced The Generalized MBE can be written mathematically as:

Where: N = initial oil in place, STB Np = cumulative oil produced, STB G = initial gas in place, SCF Gi = cumulative gas injected into reservoir, SCF Gp = cumulative gas produced, SCF We = water influx into reservoir, bbl Wi = cumulative water injected into reservoir, STB Wp = cumulative water produced, STB Bti = initial two-phase formation volume factor, bbl/STB = Boi Boi = initial oil formation volume factor, bbl/STB 25

Chapter 2

Bgi = initial gas formation volume factor, bbl/SCF Bt = two-phase formation volume factor, bbl/STB = Bo + (Rsoi - Rso)Bg Bo = oil formation volume factor, bbl/STB Bg = gas formation volume factor, bbl/SCF Bw = water formation volume factor, bbl/STB Big = injected gas formation volume factor, bbl/SCF Biw = injected water formation volume factor, bbl/STB Rsoi = initial solution gas-oil ratio, SCF/STB Rso = solution gas-oil ratio, SCF/STB Rp = cumulative produced gas-oil ratio, SCF/STB Cf = formation compressibility, psia-1 Cw = water isothermal compressibility, psia-1, Swi = initial water saturation, Δpt = reservoir pressure drop, psia = pi - p(t) p(t) = current reservoir pressure, psia

26

Chapter 2

2.2.4.1 MBE Assumptions: The MBE keeps an inventory on all material entering, leaving, or accumulating within a region over discrete periods of time during the production history. The calculation is most vulnerable to many of its underlying assumptions early in the depletion sequence when fluid movements are limited and pressure changes are small. Uneven depletion and partial reservoir development compound the accuracy problem. The basic assumptions in the MBE are as follows [5]:Constant temperature: Pressure–volume changes in the reservoir are assumed to occur without any temperature changes. If any temperature changes occur, they are usually sufficiently small to be ignored without significant error. Reservoir characteristics: The reservoir has uniform porosity, permeability, and thickness characteristics. In addition, the shifting in the gas–oil contact or oil–water contact is uniform throughout the reservoir. Fluid recovery: The fluid recovery is considered independent of the rate, number of wells, or location of the wells. The time element is not explicitly expressed in the material balance when applied to predict future reservoir performance. Pressure equilibrium: A uniform pressure is assumed to apply across the pool. The model is considered as a tank with infinite permeability. Constant reservoir volume: Reservoir volume is assumed to be constant except for those conditions of rock and water expansion or water influx that are specifically considered in the equation. Reliable production data: There are essentially three types of production data that must be recorded in order to use the MBE in performing reliable reservoir calculations. These are: 1. Oil production data, even for properties not of interest, can usually be obtained from various sources and is usually fairly reliable. 2. Gas production data is becoming more available and reliable as the market value of this commodity increases; unfortunately, this data will often be more questionable where gas is flared.

27

Chapter 2

3. The water production term need represent only the net withdrawals of water; therefore, where subsurface disposal of produced brine is to the same source formation, most of the error due to poor data will be eliminated.

28

Chapter 2

2.2.4.2 Primary Recovery Mechanism The overall performance of oil reservoirs is greatly affected by the nature of energy (driving mechanism), responsible for moving the oil to the well bore. There are basically six driving mechanisms which are [5] :1. Rock and Liquid expansion drive. 2. Depletion drive. 3. Gas-cap drive. 4. Water drive. 5. Gravity drainage drive. 6. Combination drive.

29

Chapter 2

2.2.4.2 .1Rock And Liquid Expansion Drive: An under-saturated reservoir is a reservoir that initially exists at a pressure higher than its bubble point pressure. At pressures above the bubble point pressure, crude oil, connate water and rock are the only materials present. As the reservoir pressure declines (with production), the rock and fluids expand due to their compressibilities. This compressibility is due to the expansion of individual rock grains and formation compaction. As a result of this expansion, the pore volume will be reduced as a result of a decrease in fluid pressure. This reduction in pore volume will force the crude oil and water out of the pore volume to the wellbore which explains this driving mechanism. The reservoirs under this driving mechanism, usually has a constant gas oil ratio. This driving mechanism is considered the least efficient driving force and has the lowest oil recovery rates.

30

Chapter 2

2.2.4.2 .2 Depletion Drive: This mechanism is also referred to as: Solution gas drive Dissolved gas drive Internal gas drive In this type of reservoir, the major source of energy us a result of gas liberation from the crude oil and the subsequent expansion of the solution gas as the reservoir pressure is reduced. As pressure falls below bubble point pressure, gas bubbles are liberated; these bubbles expand and force the crude oil out of the pore space as shown in figure 9.

Figure 9 Solution Gas Drive Reservoir.[8]

Cole (1969), suggested that a depletion drive reservoir can be identified by the following characteristics:[9] 1)

Reservoir pressure declines rapidly and continuously

2)

Gas Oil ratio increases to maximum ad then declines

3)

Water production is absent or negligible

4)

Well behavior: requires pumping at early stage

5)

Oil recovery ranges from 8% to 25%

31

Chapter 2

The above characteristic trends occurring during the production life of depletion drive reservoirs is shown in figure 10.

Figure 10 Production Data Of Depletion Drive Reservoir. [8]

32

Chapter 2

2.2.4.2 .3 Gas-Cap Drive: Gas-cap drive reservoirs can be identified by the presence of a gas cap with little or no water drive as shown in figure 11.

Figure 11 Gas-cap drive reservoir.[8]

The natural energy available to produce the crude oil comes from: The expansion of the gas cap The expansion of solution gas as it is liberated

Cole and Clark (1969), suggested that gas-cap drive reservoirs have the following characteristics [9]: 1)

Reservoir pressure falls slowly and continuously

2)

Gas Oil ratio rises continuously

3)

Water production is absent or negligible

4)

Well behavior: gas-cap drive reservoirs tend to flow longer than depletion drive reservoirs

5)

Oil recovery ranges from 20% to 40%

33

Chapter 2

The above characteristic trends occurring during the production life of gascap drive reservoirs is shown in figure 12 .

Figure 12 Production Data For A Gas-Cap Drive Reservoir.[8]

34

Chapter 2

2.2.4.2.4 .Water Drive: any reservoirs are bounded on a portion or all of their edges by water bearing rocks called aquifers. The aquifers may be so large compared to the reservoir where they act infinitely. They may also range down to small (almost negligible), in their effects on the reservoir performance. The aquifer may be entirely bounded by impermeable rock so that the reservoir and aquifer together form a volumetric (closed unit). On the other hand, the reservoir may be outcropped at one or more places where it may be replenished by surface water as shown in figure 13.

Figure 13 Reservoir With Water Drive .[8]

When talking about water influx, it is common to speak about edge water and bottom water drive. Bottom water occurs directly beneath the oil and edge water occurs in the flanks at the edge of the oil as shown in figure 14 . Regardless of the source of water, the water drive mechanism is the result of water moving into the pore spaces originally occupied by oil, replacing the oil and displacing it to the producing wells.

35

Chapter 2

Figure 14 Aquifer Geometries . [8]

Cole (1969), suggested that water drive reservoirs have the following characteristics [11]: 1)

Reservoir pressure remains high

2)

Gas Oil ratio remains low

3)

Water production starts early and increase to appreciable amounts

4)

Well behavior: flow until water production gets excessive

5)

Oil recovery ranges from 20% to 55%

Figure 15 shows the production data for a water drive reservoir.

Figure 15 Production Data For A Water Drive Reservoir. [8]

36

Chapter 2

2.2.4.2.5 Gravity Drainage Drive : The mechanism of gravity drainage occurs in petroleum reservoirs as a result of differences in densities of the reservoir fluids. The effects of gravitational forces can be simply illustrated by placing a quantity of crude oil and a quantity of water in a jar and agitating the contents. After agitation, the jar is placed at rest, and the denser fluid (normally water) will settle to the bottom of the jar, while the less dense fluid (normally oil) will rest on top of the denser fluid. The fluids have separated as a result of the gravitational forces acting on them. The fluids in petroleum reservoirs have all been subjected to the forces of gravity, as evidenced by the relative positions of the fluids, i.e., gas on top, oil underlying the gas, and water underlying oil. The relative positions of the reservoir fluids are shown in Figure 16 .

Figure 16 Initial Fluid Distribution In An Oil Reservoir . [8]

Gravity segregation of fluids is probably present to some degree in all petroleum reservoirs, but it may contribute substantially to oil production in some reservoirs.

37

Chapter 2

Cole (1969), stated that reservoirs under gravity drainage drive have the following characteristics [9] :1)

Reservoir pressure has variable rates of pressure decline depending on the amount of gas. In most cases, there is a rapid pressure decline.

2)

Gas Oil ratio remains low.

3)

Water production starts is absent or negligible.

4)

Oil recovery ranges from 30% to 70%.

38

Chapter 2

2.2.4.2.6 Combination: In real cases, a reservoir usually includes at least two main drive mechanisms. For instance, in the case shown in the figure below, the management of the reservoir for different drive mechanisms can be diametrically opposed (e.g. low perforation for gas cap reservoirs compared with high perforation for water drive reservoirs). If both occur as in Figure, a compromise must be required, and this compromise must take into account the strength of each drive present, the size of the gas cap, and the size/permeability of the aquifer. It is the job of the reservoir manager to identify the strengths of the drives as early as possible in the life of the reservoir to optimize the reservoir performance.

Figure 17 Combination Drive Mechanism . [8]

39

Chapter 2

2.2.4.3 Driving Indexes MBE: As discussed earlier, oil can be primarily recovered by five driving mechanisms, to determine the relative magnitude of each of these driving mechanisms, the compressibility term in the general material balance equation is neglected and the equation is rearranged as follows:

Dividing by the right hand side of the equation gives:

The terms on the left hand side of equation above represent the depletion drive index (DDI), the segregation drive (gas cap drive) index (SDI), and the water drive index (WDI) respectively. The expansion drive index (EDI), has a minor effect on the oil recovery and can be neglected (not included in the equation). Prison‘s abbreviation can be used to give the following equation [7] : DDI + SDI+ WDI+ EDI + 1 Where EDI can be neglected as mentioned earlier.

The driving index for each mechanism can be calculated for a reservoir in order to calculate the efficiency of each driving mechanism.

40

Chapter 2

2.2.4.3.1

Depletion Drive Index(Oil Zone Oil Expansion ),(DDI)

Depletion drive is the oil recovery mechanism wherein the production of the oil from its reservoir rock is achieved by the expansion of the original oil volume with all its original dissolved gas.

2.2.4.3.2

Segregation Drive Index (Gas Zone Gas Expansion),(SDI)

Segregation drive (gas cap drive) is the mechanism wherein the displacement of oil from the formation is accomplished by the expansion of the original free gas cap.

2.2.4.3.3

Water Drive Index (W DI)

Water drive is the mechanism wherein the displacement of the oil is accomplished by the net encroachment of water into the oil zone.

2.2.4.3.4

Expansion Drive Index (Rock And Liquid), (EDI)

For under saturated oil reservoirs with no water influx, the principle source of energy is a result of the rock and fluid expansion. Where all the other three driving mechanisms are contributing to the production of oil and gas from the reservoir, the contribution of the rock and fluid expansion to the oil recovery is too small and essentially negligible and can be ignored.

41

Chapter 2

2.2.4.4 MBE In Linear Form: Normally, when using the material balance equation, each pressure and the corresponding production data is considered as being a separate point from other pressure values. From each separate point, a calculation is made and the results of these calculations are averaged. However, a method is required to make use of all data points with the requirement that these points must yield solutions to the material balance equation that behave linearly to obtain values of the independent variable. The straight- line method was developed by Havlena and Odeh (1963) by starting with[10,11] :

Defining the ratio of the initial gas cap volume to the initial oil volume as:

Putting m in the equation gives:

42

Chapter 2

Let:

Where: F = Underground withdrawal Eo = Oil and Dissolved gas expansion terms Eg = Gas cap expansion term Ef,w = rock and water compression/expansion terms So we obtain:

(E1)

The above equation was developed in order to determine the following three unknowns [10,11] 1. The Original Oil in Place N 2. The cumulative water influx We 3. The original gas cap size compared to the oil zone size m.

43

Chapter 2

The straight line relationship developed by Havlena and Odeh can be used in the following six applications:

Case 1: Determination of N in volumetric undersaturated reservoirs Case 2: Determination of N in volumetric saturated reservoirs Case 3: Determination of N and m in gas cap drive reservoirs Case 4: Determination of N and We‖ in water drive reservoirs Case 5: Determination of N, m, and We in combination drive reservoirs Case 6: Determination of average reservoir pressure, p

In this study, the main aim is to calculate the IOIP (N), and so the first five cases will be considered for calculating N only.

44

Chapter 2

2.2.4.4.1 Volumetric Under saturated Reservoir For a volumetric under-saturated reservoir, the conditions associated with a driving mechanism are [5]: • We = 0, since the reservoir is volumetric • m = 0, since the reservoir is undersaturated • Rs = Rsi = Rp, since all produced gas is dissolved in the oil Applying the above condition to Equation (E1) gives:

(E2)

Or

0

(E2)

To calculate N, a plot of (F/ Eo+ Ef ,w) versus cumulative production Np is 0 plotted. Figure shows an example of this plot. Dake (1994) suggest that this plot can take two shapes [12]. As shown in figure 9, Line A implies that the reservoir is a volumetric reservoir. This defines a purely depletion drive reservoir whose energy drives solely form the expansion of rock, connate water and oil. Lines B and C, implies the existence of a water drive in which the reservoir was energized by water influx, Line B represents a moderate aquifer whose degree of energizing decreases with time. While, Line c represents a strong aquifer who is acting infinitely. In all cases, IOIP (N) is the ordinate value of the plateau as shown in figure 18.

45

Chapter 2

Figure 18 Classification Of The Reservoir. [5]

46

Chapter 2

2.2.4.4 .2Volumetric Saturated Reservoirs A saturated oil reservoir is an oil reservoir that originally exists at its bubble point pressure (Pb). The main driving mechanism in saturated reservoirs results from the liberation and expansion of the solution gas as the pressure drops below bubble point pressure. Havlena and Odeh equation (Equation (E1)) can be written as [10, 11]:

(E3) Assuming that the water and rock expansion term Ef,w is negligible in comparison with the expansion of solution gas. This relationship can be used to determine N for saturated reservoirs by plotting F versus Eo. This should result in a straight line going through the origin with a slope of N as shown in figure 19.

Figure 19 Determining N For Saturated Reservoirs . [5]

47

Chapter 2

2.2.4.4 .3 Gas Cap Drive Reservoirs In gas cap reservoirs, the expansion of the gas-cap gas is the dominant driving mechanism and assuming that natural water influx is negligible (We=0), the Havlena and Odeh MBE (Equation (E1)) can be written as:

(E4) The way in which equation (E4) is applied depends on the number of unknowns in the equation, there are three possible unknowns in equation (E4). N is unknown, m is known. M is unknown, N is known. N and m are unknown. The first and last case will be considered, because in the second case, N is known ,and as mentioned earlier; only methods to determine N will be discussed.

Unknown N, Known m: Equation 3 indicates that when m is known, a plot of F versus (Eo + m Eg) on a Cartesian scale would produce a straight line through the origin with a slope of N as shown in figure 20.

48

Chapter 2

Figure 20 F versus Eo + m Eg . [5]

N and m are unknown: If both N and m are unknown, equation (E4) can be re-expressed as:

(E5) A plot of F/Eo versus Eg/Eo should be linear with intercept N and slope mN as shown in figure 21.

Figure 21(F/Eo) versus (Eg/Eo). 49

Chapter 2

2.2.4.4 .4 Water Drive Reservoirs Dake (1978) points out that the term Ef,w can be neglected in water drive reservoirs. And so equation (E1) can be written as [13]: (E6) If, the reservoir has no initial gas cap, equation (E6) can be re-written as: (E7) Dake (1978) points out that in attempting to use the above two equations to match the production and pressure history of a reservoir, the greatest uncertainty is always the determination of the water influx (We) [13]. In fact, in order to calculate the influx the engineer is confronted with what is inherently the greatest uncertainty in the whole subject of reservoir engineering. The reason is that the calculation of (We) requires a mathematical model which itself relies on the knowledge of aquifer properties. Three water influx models will be discussed. These models are: Pot aquifer model Schilthuis steady-state model. Van Everdingen- Hurst unsteady state model. The assumed reservoir for these models will be a water drive reservoir with no gas cap which is represented by the following equation: (E8)

50

Chapter 2

Pot-Aquifer model: The pot aquifer model is used to represent water influx and is summarised by the following equation (E8)

(E9) The aquifer properties cw, cf, h, ra, and θ are rarely available and they can be combined as one unknown (K) and so equation (E9) can be written as: (E10) Combining equations (E8) and (E10) gives:

(E11)

Equation (E11) implies that a plot of (F/Eo) as a function of (∆P/Eo) would yield a straight line with an intercept of N and slope of K as shown in figure 22. 51

Chapter 2

Figure 22 (F/Eo) As A Function Of (∆P/Eo) .[5]

Schilthuis steady-state model: The steady state aquifer model was proposed by Schilthuis (1936) is given by [11]:

(E12) 52

Chapter 2

Combining equation (E8) with equation (E12) gives:

(E13) Plotting F/Eo versus

results in a straight line with an intercept N and

a slope (C) that describes the water influx as shown in figure 23.

Figure 23 Steady State Model Applied To MBE.[5]

53

Chapter 2

Van Everdingen - Hurst unsteady state model: The Van Everdingen-Hurst unsteady state model is given by [14]:

(E14)

With:

Van Everdingen and Hurst presented the dimensionless water influx WeD as a function of the dimensionless time tD and dimensionless radius rD that are given by:

Combining equation (E8) with (E14) gives:

(E14) 54

Chapter 2

The proper methodology of solving the above linear relationship is summarized in the following steps. Step 1. From the field past production and pressure history, calculate the underground withdrawal F and oil expansion Eo. Step 2. Assume an aquifer configuration, i.e., linear or radial. Step 3. Assume the aquifer radius ra and calculate the dimensionless radius rD. Step 4. Plot (F/Eo) versus (Σ Δp WeD)/Eo on a Cartesian scale. If the assumed aquifer parameters are correct, the plot will be a straight line with N being the intercept and the water influx constant B being the slope. It should be noted that four other different plots might result. These are: • Complete random scatter of the individual points, which indicates that the calculation and/or the basic data are in error. • A systematically upward curved line, which suggests that the assumed aquifer radius (or dimensionless radius) is too small. • A systematically downward curved line, indicating that the selected aquifer radius (or dimensionless radius) is too large. • An s-shaped curve indicates that a better fit could be obtained if a linear water influx is assumed.

Figure 24 shows a schematic illustration of Havlena-Odeh (1963) methodology in determining the aquifer fitting parameters [10,11].

55

Chapter 2

Figure 24 Havlena And Odeh Straight Line Plot . [10.11]

56

Chapter 2

2.2.4.4 .5 Combination Drive Reservoir The general straight line MBE equation is illustrated in equation E1 and is given by:

(E1) Where:

Havlena and Odeh differentiated equation (E1) with respect to pressure and rearranged the equation to eliminate m to give [10, 11]:

(E15) Where:

57

Chapter 2

A plot of the left-hand side of equation (E15) versus the second term on the right for a selected aquifer model should, if the choice is correct, provide a straight line with unit slope whose intercept on the ordinate gives the initial oil in place, N. After determining N and We, equation (E1) can be used to solve directly for m.

The derivatives used in equation (E15) can be evaluated numerically by any finite difference technique including forward , backward and central techniques.

58

Chapter 2

2.2.4.5 Water Influx[5] Many reservoirs are bounded on a portion or all their perimeters by water bearing rocks – aquifers. As reservoir fluids are produced, a pressure differential develops between the surrounding aquifer and the reservoir. The aquifer reacts by encroaching across the original hydrocarbon-water contact. Aquifers retard pressure decline in reservoirs by providing a sourceof water influx We. We is a function of time (production). We is dependent on the size of aquifer and the pressure drop from the aquifer to the reservoir.

2.2.4.5 .1 Steady-state method Schilthuis Steady-state method is the simplest model for water influx. Water influx is proportional to the pressure drawdown (pi – p):

Integrating Eq gives Where: k′= water flux constant, bbl/day-psi P = pressure at the original oil-water contact pi= initial pressure at the external boundary of the aquifer.

Calculation of k′and Wefrom production data: In a reasonably long period, if the production rate and reservoir pressure remain substantially constant, there is:

59

Chapter 2

The equation can be rearranged to:

If the pressure stabilizes and the withdraw rates are not reasonably constant, water influx in the pressure stabilized period Δt can be calculated from the total productions of oil, gas and water within Δt:

Then k′can be found from the following equation:

For an under-saturated oil reservoir and at pressures higher than the bubble point pressure, Equation can be simplified to:

60

Chapter 2

2.2.4.5.2 VEH unsteady-state method Van Everdingen and Hurst solutions to the single-phase unsteady state flow equation are used to calculate water influx. The hydrocarbon reservoir is the inner boundary condition and is analogous to the well and the aquifer is the flow medium analogous to the reservoir. Properties of aquifer are assumed homogeneous and constant. Reservoir and aquifer are assumed cylindrical in shape.

Figure 25 VEH Cylindrical In Shape Reservoir.

Water flux is calculated by the following equations:

In Where WeD is given as a function of dimensionless time D t and dimensionless radius D r (see Tables 5and Figures 26):

The dimensionless time and dimensionless radius are defined as

61

Chapter 2

Figure 26 Dimensionless Time And Fluid Influx Chart.[5]

Table 5 Dimensionless Time And Fluid Influx Table .[5]

62

Chapter 2

Values for Δpj are determined from measure pressures. The pressure changes are calculated as follows to approximate the pressure-time curve:

Figure 27 Pressure Steps Used To Approximate The Pressure-Time Curve . [5]

2.2.4.5.3 Fetkovich Pseudo steady-state method The size of the aquifer is known-finite aquifer. Any water influx from the aquifer depletes the pressure accordingto the material balance equation. Steps of calculation of water influx by using Fetkovich Pseudo steady state method: 1. Calculate the initial encroachable water, Wei(in bbls), in the aquifer

63

Chapter 2

2. Calculate the productivity index, J, for flow from the aquifer to the reservoir a) For finite aquifer with no flow at the outer boundary:

b) For finite aquifer with constant pressure the outer boundary:

3. Calculate the average reservoir pressure during a time step:

4. Calculate the water influx during a time step

5. Calculate the total cumulative water influx at the current time

6. Calculate the average aquifer pressure at the end of the current timestamp

7. Repeat Steps 3 to 6 for next time step. 64

Chapter 2

2.3 Enhanced Oil Recovery (EOR) [16,17] The life of an oil well goes through three distinct phases where various techniques are employed to maintain crude oil production at maximum levels. The primary importance of these techniques is to force oil into the wellhead where it can be pumped to the surface. Techniques employed at the third phase, commonly known as Enhanced Oil Recovery (EOR), can substantially improve extraction efficiency. Laboratory development of these techniques involves setups that duplicate well and reservoir conditions. Core Flooding Pumps or Core Analysis Pumps, such as Teledyne Isco Syringe Pumps, are used in laboratory testing of these Enhanced Oil Recovery (EOR) techniques.

The Three Stages of Oil Field Development Primary Recovery : In Primary Recovery, oil is forced out by pressure generated from gas present in the oil. Secondary Recovery : In Secondary Recovery, the reservoir is subjected to water flooding or gas injection to maintain a pressure that continues to move oil to the surface. Tertiary Recovery : Tertiary Recovery, also known as Enhanced Oil Recovery (EOR), introduces fluids that reduce viscosity and improve flow. These fluids could consist of gases that are miscible with oil (typically carbon dioxide), steam, air or oxygen, polymer solutions, gels, surfactant-polymer formulations, alkalinesurfactant-polymer formulations, or microorganism formulations.

2.3 .1 Miscible EOR Commonly applied in West Texas, this method usually employs supercritical CO2 to displace oil from a depleted oil reservoir with suitable characteristics (typically containing ―light‖ oils). Through changes in pressure and temperature, carbon dioxide can form a gas, liquid, solid, or supercritical fluid. When at or above the critical point of pressure and temperature, supercritical CO2 can maintain the properties of a gas while having the density of a liquid. Injected miscible CO2 will mix thoroughly with the oil within the reservoir such that the interfacial tension between these two substances effectively disappears. CO2 can also improve oil recovery by dissolving in, swelling, and reducing the viscosity of oil.

65

Chapter 2

In deep, high-pressure reservoirs, compressed nitrogen has been used instead of CO2. Hydrocarbon gases have also been used for miscible oil displacement in some large reservoirs. CO2, nitrogen, hydrocarbon gases, and flue gases have also been injected to immiscibly displace oil. At one extreme of conditions, these displacements may simply amount to ―pressure maintenance‖ in the reservoir (a secondary recovery process). Depending on oil character, gas composition and pressure, and temperature, the displacements could have a range of efficiencies up to and approaching a miscible displacement. CO2 has also been injected in a ―huff ‗n puff‖ or cyclic injection mode, like cyclic steam injection.

2.3 .2 Chemical EOR Three chemical flooding processes include polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer (ASP) flooding. In the polymer flooding method, water-soluble polymers increase the viscosity of the injected water, leading to a more efficient displacement of moderately viscous oils. Addition of surfactant to the polymer formulation may, under very specific circumstances, reduce oil-water interfacial tension to almost zero—displacing trapped residual oil. Although no large-scale surfactant-polymer floods have been implemented, the process has considerable potential to recover oil. A variation of this process involves addition of alkaline to the surfactant-polymer formulation. For some oils, alkaline may convert some acids within the oil to surfactants that aid oil recovery. The alkaline may also play a beneficial role in reducing surfactant retention in the rock. For all chemical flooding processes, inclusion of a viscosifier (usually a water-soluble polymer) is required to provide an efficient sweep of the expensive chemicals through the reservoir. Gels are also often used to strategically plug fractures (or other extremely permeable channels) before injecting the relatively expensive chemical solutions, miscible gases, or steam.

2.3.3 Other EOR Processes Over the years, a number of other innovative EOR processes have been conceived, including injection of carbonated water, microorganisms, foams, alkaline (without surfactant), and other formulations. These methods have shown varying degrees of promise, but require additional development before such applications will become common. 66

Chapter 2

Figure 28 EOR Injection Method.[17]

In our case we will focus in chemical EOR Why we use chemical EOR? Conventional oil RF 10) :By using

Interpolation: Table 33 Calculate TD at re/rw >10 [5]

Table 34 Calculate (QT)

7) Then Calculate ∑Qt.∆P :

119

CHAPTER 3

Table 35 Calculate ∑Qt.∆P

Then put the final result

Table 36 Input QT ,∑Qt.∆P.

120

CHAPTER 3

8) Calculate We uss

Table 37 Calculate We uss

9) Calculate NP :

Enter Wp Values : Table 38 Input Wp ,NP

10)

Calculate Wi :

―Assume this const. Until We USS curve intercepts with We MBE curve‖ ―

‖ 121

CHAPTER 3

First assume it = 1 Table 39 Calculate Wi

11) Calculate NP*βo ,WP*βw, WI*βw ,∆P( ) Table 40 Calculate NP*βo ,WP*βw, WI*βw ,∆P

12) Calculate : N*βoi*Ce*∆P Table 41 Calculate N*βoi*Ce*∆P

122

CHAPTER 3

13) Calculate We MBE :

Table 42 Calculate We MBE

14) Draw a Chart Between P with ( WE MBE& WE USS) :

Figure 47 Chart between P with ( wepe& we uss))

15) Change the value of the const. Until We uss intercepts with We mbe Const. Should be less than 2.5 At const. = 1.2992 the 2 curves are intercepted

123

Millions

CHAPTER 3 3.93 3.92 3.91 3.9 We uss

3.89

me

3.88 3.87 3.86 1395

1400

1405

1410 P

1415

1420

1425

Millions

Figure 48 Chart Between P With ( Wepe& We Uss)By Using Mew Wi. 3.93 3.92 3.91 3.9 uss 3.89

mbe

3.88 3.87 3.86 1395 1400 1405 1410 1415 1420 1425

Figure 49 Predicted p .

16) Get the P. at the intercept P. = 1416 17) Repeat these steps for every 2 years until : NP/Wi = 2.5 Then the prediction stops .

124

CHAPTER 3

3.2.2 Reservoir Management Spread sheet It‘s an Excel sheet depends on mathematical calculation by using Microsoft Macros to calculate reservoir engineering purpose. The benefits of using Reservoir Management Spread sheet

Interpolate the PVT data to match data with reservoir pressure. Draw Production History Matching Curve. Reservoir Production Prediction. Comparing the production will be with changing water viscosity by (Polymer Flooding).

The Required Data

Start of Production date . Initial pressure . Reservoir Area and hight. Number and names of wells , wells types (production or injection), wells location and initial flow rate per day PVT data from lab or by correlations at different pressures. Reservoir pressure for each well along production history. Injection water viscosity.

Steps:1- Insert wells information.

Insert initial pressure and starting of production date Insert well name, Type and initial flow rate in bbl/day

Figure 50 Reservoir Management Spread Sheet Wells Input.

125

CHAPTER 3 2-

Press (Pressure Matcher) to insert wells pressures along production history.

Figure 51Reservoir Management Spread Sheet Pressure Input.

3- Press (MATCH) to history matching the pressure with time.

Figure 52 Pressure Matching

4- From Fig.53 press (PVT LAB MATCHER) to insert pvt lab data and start to match the data with different reservoir pressure.

Figure 53 Reservoir Management Spread Sheet PVT Input .

126

CHAPTER 3

5- Press (GO TO LAB) to start matching the PVT data with wells pressure.

Figure 54 Reservoir management spread sheet PVT Matching .

6- From Fig. 55 press (PREDICTION) , Insert (Wells locations, Reservoir area, Height , Initial injection water viscosity and injection water with polymers viscosity) then press (Predict).

Figure 55 Reservoir Management Spread Sheet Well Locations.

127

CHAPTER 3

7- The following fig shows the prediction of the production of the reservoir.

Figure 56 Reservoir Management Spread Sheet Prediction

8- The following fig showing prediction of reservoir production behavior at initial injection water viscosity and changing in water viscosity.

Figure 57 Reservoir Management Spread Sheet Prediction by chemical effect

128

CHAPTER 3

3.2.3MBAL [24] 3.2.3.1 Montecarlo Simulation Tool [24] : The tool enable the user to perform statistical evaluation of reservoir .distribution can be assigned to variable like porosity or thickness of reservoir and the program will generate the range of probability associated with reserve range. Decline Curve Analysis : Production data can be fitted to Hyperbolic , exponential or Hermic decline . these is can be the extrapolation in future for generation forecasts. Software steps: 1-Choose Mote Carlo Tool From Tool Manu As Shown:

Figure 58 Choosing Monte Carlo Tool.

129

CHAPTER 3

2- Defining the general option :

Figure 59 System Option Window

3- enter the PVT fluid properties data form PVT menu :

Figure 60 PVT Menu

4- then enter the data required in the new window as shown :

Figure 61 Data Input 130

CHAPTER 3

5-Match PVT data :

Figure 62 Match PVT data

6- Then choose Distribution from Input menu:

Figure 63 Selecting Distributions.

131

CHAPTER 3

7- Entre the required data in the window where the bulk volume is calculated from reservoir geology information :

Figure 64 Distributions.

8- Then press ― Calc ― , to watch the results .

132

CHAPTER 3

3.2.3.2 MBE Tool [24] :

Data loading History matching Prediction Field development planning using MBE will be applied using MBAL software, the workflow can be divided into:

1. Data loading: This step is the initial step of the development process. In this stage, the available data of the reservoir is loaded into the software, and the general options of the model are determined. These data include: i. Fluid properties ii. PVT properties iii. Estimation of the IOIP from the results of Eclipse simulation results. iv. Production start date. v. Petro-physical data vi. Relative permeability data. vii. Historical data (production and pressure) After loading the data, matching process should be applied for the fluid properties and PVT data as discussed earlier in the volumetric method. The main output of this step is the relative permeability plot and the cumulative oil production and pressure plot.

133

CHAPTER 3

2. History matching: History matching process involves matching the historical data with the data predicted by the model. 3. Model validation: Before using the model for any future prediction, the model‘s ability to predict the past performance in agreement with the input data must be checked. In order to check the model, the model is run on prediction from the start till the end data of the input data. A plot of the cumulative production and historical pressure can be constructed to compare the input data with the prediction data, if the values match; then the model is ready for the prediction process. 4. Prediction: After making sure that the model is valid for prediction, we have to define the target and constraints for the prediction and then check the reservoir behavior under different scenarios.

Software step: 1. Data loading Defining model general options

Figure 65 General Option Widow.

134

CHAPTER 3

Fluid properties From PVT list , choosing fluid properties

Figure 66 PVT list .

Then data would be entered

Figure 67 Black Oil ( Data Input).

135

CHAPTER 3

Then match the data by using Match button and input the data in the table

Figure 68 PVT Matching.

Then click Match and choose data which will match on such as (Bubble point , Gas oil ratio , Oil FVF and Oil Viscosity ) as shown and press Calc button

Figure 69 Matching.

136

CHAPTER 3

Then click Plot button to plot the matched data graphs as shown in the figure :

1-Oil FVF

Figure 70 Oil FVF Curve.

2-oil viscosity

Figure 71 Oil Viscosity Curve.

137

CHAPTER 3

3- Gas Oil Ratio

Figure 72 GOR Curve.

Reservoir parameters The next step is to define the tank (reservoir parameters which include the estimation of the IOIP , average petro-physical data (porosity, water saturation), the relative permeability data, and production history. Figure 73 shows the determination of tank parameters From Input choose Tank Data

Figure 73 Input List.

138

CHAPTER 3

1-Input tank parameters as shown :

Figure 74 Tank Parameters.

2-the water influx of the aquifer was defined using Van EverdingenHurst model discussed earlier in the literature review section as shown:

Figure 75 Water Influx.

139

CHAPTER 3

3-Then enter the rock compressibility by correlation as shown

Figure 76 Rock Compressibility.

4-Enter the rock compaction reversible as shown :

Figure 77 Rock Compaction. 140

CHAPTER 3

5- Relative permeability from tables

Figure 78 Relative Permeability.

The plots of permeability

Figure 79 Relative Permeability Curves.

141

CHAPTER 3

6- production History

Figure 80 History Matching Table.

input the production history by using Import will appear

Figure 81 Import Window.

142

a new window

CHAPTER 3

Choose ―Browse‖ and identify the file location then choose " done " in the new window choose ― Tab Delimited ― then choose "done "

Figure 82 Import Setup.

choose data shown with given field names

Figure 83 Import file. 143

CHAPTER 3

2- History matching Click on the History Matching button then choose Run Simulation to run the simulation

Figure 84 History Matching List.

In the new window click Clac button

\

Figure 85 Run History Matching.

144

to start calculation

CHAPTER 3

Then choose : 1- Analytical method :

Figure 86 Analytical Method.

2-Graphical method :

Figure 87 Graphical method. 145

CHAPTER 3

3- energy plot :

Figure 88 Energy Plot.

4-WD function plot :

Figure 89 WD Function Plot.

146

CHAPTER 3

4-prediction : The main objective of this study is the identification and evaluation of the remaining potential in existing producing zones.

Prediction steps : 1-choose production prediction from prediction set up :

Figure 90 Production Prediction List.

2-entire the data required as shown

Figure 91 Prediction Calculation Setup. 147

CHAPTER 3

3- then choose prediction and constrains and enter the required data

Figure 92 Tank Prediction Data.

4-Then run the simulation and click Calc

Figure 93 Run Simulation Window. 148

CHAPTER 3

3.2.4 ECLIPSE [21] As shown in the literature review before the importance of using software or especially simulators, Here starts to know the steps of using the Reservoir Simulation (ECLIPSE).

ECLIPSE Data File Its consist of eight sections each section specialized in a specific data to input in it as shown:

Figure 94 Data File Section.

Start the Data Input Open New Text pad file and start input data sections

1- RUNSPEC The RUNSPEC section is the first section of an ECLIPSE data input file. It contains the run title, start date, units, various problem dimensions (numbers of blocks, wells, tables etc.), The RUNSPEC section must always be present. 149

CHAPTER 3

The used data code :( TITLE, START, DIMENS, OIL, GAS, WATER, DISGAS, FIELD,EQLDIMS ,TABDIMS, WELLDIMS, AQUDIMS) each of this data code require a specific data, ECLIPSE Manual must had used for helping what this codes needs.

2- GRID The GRID section determines the basic geometry of the simulation grid and various rock properties (porosity, absolute permeability, net-to-gross ratios) in each grid cell. From this information, the program calculates the grid block pore volumes, mid-point depths and inter-block transmissibilities. The actual keywords used depend upon the use of the radial or cartesian geometry options. The program accepts the radial form in a cartesian run and vice versa, but issues a warning.

The used data code :(TOPS,DX, DY, DZ, PERMX, PERMY, PERMZ, PORO, NTG, GRIDFILE, INIT, NOECHO, PINCH).

3- EDIT The EDIT section contains instructions for modifying the pore volumes, block center depths, transmissibilities, diffusivities, and nonneighbor connections (NNCs) computed by the program from the data entered in the GRID section. It is entirely optional.

150

CHAPTER 3

4- PROPS Tables of properties of reservoir rock and fluids as functions of fluid pressures, saturations and compositions (density, viscosity, relative permeability, capillary pressure, etc.). Contains the equation of state description in compositional runs.

The used data code :(SWFN, SGFN, SOF3, ROCK, DENISITY, PVDG, PVTO, PVTW, AQUATAB)

5- REGIONS ` Empty, because this section used for divide the reservoir in different regions and different properties.

6- SOLUTION The SOLUTION section contains sufficient data to define the initial state (pressure, saturations, compositions) of every grid block in the reservoir .

The used data code :(EQUIL, RSVD, RPTRST, RPTSOL)

7- SUMMARY Specification of data to be written to the Summary file after each time step. Necessary if certain types of graphical output (for example watercut as a function of time) are to be generated after the run has finished. If this section is omitted no Summary files are created.

151

CHAPTER 3

The used data code :(RPTONLY, DATE, EXCEL, SEPARATE, ELAPSED, FOIP, FOPR, FOPRH,FOPT,FOPTH,FLPR,FLPRH,FLPT,FLPTH,GOPR,GOPRH, GOPT,GOPTH,GWPR,GGPR,WOPR,WOPRH,WOPT,WOPTH, WWPR,WWPRH,WGPR,WGPRH,FWPR,FWPRH,FWCT,FWCTH, FWPT,FWPTH,GWPR,GWPRH,GWCT,GWCTH,GWPT,GWPTH, WWPRH,WWCTH,WWPT,WWPTH,FGIP,FGPR,FGPRH,FGOR, FGORH,FGPT,FGPTH,RGIP,GGPR,GGPRH,GGOR,GGORH,GGPT, GGPTH,WGPR,WGPRH,WGOR,HWGPT,WGPTH,FPR,RPR,WBHP, WBP5,WBP9,WBHPH,WPI,WPIH,FAQR,FOEW,ROEW,TCPU, WMCTL,WLPR,WLPRH,WPR,AAQR,FAQR,FAQT, AAQP,FOPV,FWPV, WLPT, WLPTH, WWIR,WWIT, FWIR, FWIT,WPI, WBP9)

8- SCHEDULE Specifies the operations to be simulated (production and injection controls and constraints) and the times at which output reports are required. Vertical flow performance curves and simulator tuning parameters may also be specified in the SCHEDULE section.

The used data code :(WELSPECS, COMPDAT, WCONPROD)

WCONHIST,

WCONINJE,

DATES,

After Input the reservoir Data in the Data File, Starting the next step that‘s running the simulation

152

CHAPTER 3

Running the Simulator:1- From the Program Launcher ballet press ECLIPSE

Figure 95 Simulator Preface.

2- Browsing computer drivers to select input data file and press RUN

Figure 96 Run The Simulator.

3- Running the Simulator till end and having confirmation that there is no warning massages or errors

Figure 97 Running The Simulator.

153

CHAPTER 3

4- After running to show the calculation of OOIP, open the file (.PRT) from input folder and search for OOIP

Figure 98 Print File Location.

Figure 99 Original Oil In Place (OOIP).

5- Showing the Model, From Program Launcher select (FLOVIZ)

Figure 100 Start FLOVIZ 154

CHAPTER 3

6- After pressing (RUN), FILEOPENECLIPS

Figure 101 Run The Model 1 .

Figure 103 Run The Model 2.

Figure 102 Run The Model 3 .

155

CHAPTER 3

Figure 105 Reservoir Model .

7- (GRID PROPERTEY ) Button enable to show the different properties required and response of model with TIME factor, that can be selected from (PLAY,PAUSE, …ETC. ) Buttons which at the top bar of the software.

Figure 104 (FLOVIZ Parameters).

156

CHAPTER 3

To get the last report and drawing the curves of different requirements from production rates (Gas, Oil & Water) along reservoir life from the beginning till the predicted depletion, Select from program Launcher (OFFICE).

Figure 106 RUN OFFICE.

8- Select REPORTFILEOPEN VECTORS.

SUMMERY

Figure 107 Load All Vectors .

157

LOAD

ALL

CHAPTER 3

9- At (INPUT), select the vectors required to plot or shown in the output file then press (GENERATE REPORT) .

Figure 108 Input Variables .

10- To see the report Press (OUTPUT) then select showing it as table or Plot as required.

Figure 109 Output OFFICE.

158

CHAPTER 3

Figure 110 OFFICE Output table.

Figure 111 OFFICE Output Charts .

11- Finally, may have more than one plot and different vectors as required.

159

CHAPTER 4

CHAPTER4 4 Result 4.1 PVT Correlations [5] Gas Solubility (Rs) The used correlations : Standing‘s Glaso‘s

Gas Solubility 200 180 160 140 120 Rs 100 80 60 40 20 0

Actual Modified Rs Glaso Standin 0

2000 4000 Pressure

6000

Figure 112 Gas Solubility

The Best and suitable correlation was (Standing correlation) with Average Absolute Error (AAE%) = 50.98 %

x= 0.0125 API - 0.00091(T - 460)

the modified correlation

160

CHAPTER 4

Gas Specific gravity From knowing the gas specific gravity in the separator enabling to calculate the gas specific gravity in different reservoir conditions by adding the factor Delta (∆) from the followed chart. 0.2 0.1 0 ∆ -0.1

0

100

200

300

400

500

600

700

800

-0.2 -0.3 ∆= -6E-15 Poly. (p,delta)

p,delta

P5

Figure 113

p + 1E-11 P4 - 9E-09P3 + 1E-06P2 + 0.001P - 0.255 R² = 1

Correction.

At known pressure -15

∆= (-6×10

5

-11

P )+(10

4

-9

3

-6

2

P )-(9×10 P )+(10 P )+(.001P)-.255

=

±(∆)

Formation Volume Factor (Bo) The used correlatins:Above Bubble Point Pressure (Calhoun's correlation) Calhoun's correlation

161

CHAPTER 4

Below Bubble Point Pressure Standing's correlation Glaso‘s Correlation The Vasquez-Beggs Correlation Standing's correlation

Glaso’s Correlation

The Vasquez-Beggs Correlation

The Suitable Correlation where

PPb Calhoun's correlation Petrosky-Farshad Correlation Chew-Connally PPb Vasquez-Beggs

166

50.98 ---1.282454 1.033 19.11 2.972 0.946866842 8.28

CHAPTER 4

4.2 History Matching Table 46 History Matching.

∆t days

Date

T press,psi year

t days

NP (bbl)

Oct-63

1963

3550

0

Dec-63

1963

3500

60.8

60.8

131161.4

36833.19739

69.18792

0

Dec-65

1965

3110

730

790.8

1594203

457607.4514

1012.66

0

Dec-67

1967

2860

730

1521

2258608

690542.993

1320.86

0

Dec-69

1969

2695

730

2251

2874789

906562.8094

1346.02

0

Dec-71

1971

2555

730

2981

3360180

1057850.842

3943.711

0

Dec-73

1973

2415

730

3711

4553037

1338178.666

6660.91

0

Dec-75

1975

2275

730

4441

4595367

1347607.682

6660.91

0

Dec-77

1977

2165

730

5171

4595367

1347607.682

6660.91

0

Dec-79

1979

2055

730

5901

5856330

1793137.517

9315.21

0

Dec-81

1981

1970

730

6631

7480535

2408742.788

97529.81

0

Dec-83

1983

1860

730

7361

11147941

3251562.624

124991.1

0

Dec-85

1985

1805

730

8091

17339241

4279254.74

593802.2

912552.4

Dec-87

1987

1695

730

8821

21990877

5659457.859

1791955

5727963

Dec-89

1989

1665

730

9551

27760281

7581882.371

3303377

9440997

Dec-91

1991

1600

730

10281 32935028

8540004.594

5576024

11020377

Dec-93

1993

1525

730

11011 37532647

9438303.772

7078767

18805440

Dec-95

1995

1470

730

11741 41055155

10393282.99

8506195

27964291

Dec-97

1997

1390

730

12471 43656149

10987734.77

9514156

33643078

Dec-99

1999

1335

730

13201 45965899

11659207.85

10828708

38510358

Dec-01

2001

1335

730

13931 51218395

12879859.3

12529240

47821449

Dec-03

2003

1350

730

14661 56173602

14039769.53

14640220

65198390

Dec-05

2005

1360

730

15391 60766000

15604244.58

17798347

78063401

Oct-07

2007

1390

669.2

16060 64211703

16789192.91

21056041

91329803

167

GP(MMSCF) WP(bbl) WI(bbl)

CHAPTER 4

Millions

NP

WP

WI

Pressure

100

4000 3500

80 3000

Wp,Wi,Np (bbl)

60

40

2000

Pressure

2500

1500 20 1000 0 1960

1965

1970

-20

1975

1980

1985

1990

1995

2000

2005

2010500 0

time (YEARS)

18

4000

16

3500

14

3000

Gp(MSCF)

12 2500 10 2000 8 1500 6 1000

4

500

2 0 1960

1970

1980 1990 Time(years)

Figure 121 Gp Vs Years

168

2000

0 2010

Pressure(PSIA)

Millions

Figure 120 Wp,Wi,Np (bbl) Vs Years

GP(MMSCF) press,psi

CHAPTER 4

PVT Matching

Table 47 PVT Matching.

169

CHAPTER 4

Cw, Co, Rs 200

0.000014

180

0.000012

160 0.00001

140 120

0.000008

100 0.000006

80 60

0.000004

40 0.000002

20 0 0

500

1000

1500

Pb

2000 Rs

2500 Co

3000

3500

0 4000

Cw

Figure 122 Cw,Co,Rs

1.18

5 4.9

1.175 4.8 1.17

4.7 4.6

1.165 4.5

Bo 1.16

4.4

Bo

4.3

Mo

1.155 4.2 1.15 0

500

1000

1500

Pb

2000 P

2500

Figure 123 Bo, Mo

170

3000

3500

4.1 4000

Undersaturated Oil Reservoir

Active Bottom water Drive

Aquifer State

Driving Mechanism

Reservoir Type

CHAPTER 4

Unsteady state with infinity Aquifer Boundary

Reservoir type: under saturated reservoir with active water drive Aquifer type: Unsteady state with infinite Aquifer boundary OOIP=205749458 STB

Millions

(F-Wi.Bw)/Eo

re/rw=infinty 300 250 200 150 re/rw=infint y

100 50 0 0

10

20

30

40 Millions

∑Qt.∆P/Eo

Figure 124 re/rw=infinty

171

Linear (re/rw=infin ty)

CHAPTER 4

4.3 Prediction The project gets the prediction from ends of available data times : 2009, 2011, 2013, 2015, 2017, 2019 get Wi/Np and then ΔWi/Np as shown :

Table 48 Wi/Np & dWi/Np

ΔWI/NP

Time

WI/NP

2009

1.2992

2011

1.326

0.0268

2013

1.3524

0.0264

2015

1.3775

0.0251

2017

1.4021

0.0246

2019

1.4265

0.0244

172

CHAPTER 4

Then get (avg: ΔWI/NP) which equals = 0.0253625

Table 49 Prediction Calculation T

NP

NP/N

WP

WI

WI/NP

WI/VP

2009

68000000

0.330497555

22157428

88345600

1.2992

0.223612

2011

72000000

0.349938587

24905428

95472000

1.326

0.241649

2013

76000000

0.36937962

27813428

102782400

1.3524

0.260153

2015

80000000

0.388820652

30881428

110200000

1.3775

0.278927

2017

84000000

0.408261685

34109428

117776400

1.4021

0.298104

2019

88000000

0.427702718

37497428

125532000

1.4265

0.317734

2021

92000000

0.44714375

41045428

133571350

1.451863

0.338082

2023

96000000

0.466584783

44753428

141813600

1.477225

0.358944

2025

100000000

0.486025816

48621428

150258750

1.502588

0.38032

2027

104000000

0.505466848

52649428

158906800

1.52795

0.402209

2029

108000000

0.524907881

56837428

167757750

1.553313

0.424612

2031

112000000

0.544348913

61185428

176811600

1.578675

0.447528

2033

116000000

0.563789946

65693428

186068350

1.604038

0.470958

2035

120000000

0.583230979

70361428

195528000

1.6294

0.494901

2037

124000000

0.602672011

75189428

205190550

1.654763

0.519358

2039

128000000

0.622113044

80177428

215056000

1.680125

0.544328

2041

132000000

0.641554076

85325428

225124350

1.705488

0.569812

2043

136000000

0.660995109

90633428

235395600

1.73085

0.59581

2045

140000000

0.680436142

96101428

245869750

1.756213

0.622321

2047

144000000

0.699877174

1.02E+08

256546800

1.781575

0.649346

2049

148000000

0.719318207

1.08E+08

267426750

1.806938

0.676884

2051

152000000

0.73875924

1.13E+08

278509600

1.8323

0.704936

2053

156000000

0.758200272

1.2E+08

289795350

1.857663

0.733501

2055

160000000

0.777641305

1.26E+08

301284000

1.883025

0.76258

2057

164000000

0.797082337

1.32E+08

312975550

1.908388

0.792172

2059

168000000

0.81652337

1.39E+08

324870000

1.93375

0.822278

2061

172000000

0.835964403

1.46E+08

336967350

1.959113

0.852898

2063

176000000

0.855405435

1.53E+08

349267600

1.984475

0.884031

2065

180000000

0.874846468

1.6E+08

361770750

2.009838

0.915678

2067

184000000

0.894287501

1.67E+08

374476800

2.0352

0.947838

2069

188000000

0.913728533

1.74E+08

387385750

2.060563

0.980512

173

CHAPTER 4

Then predict that : The reservoir Abundant time is 2069 as : NP/N =0.913728533 and WI/VP=0.980512 and this is the maximum acceptable values for each of them !!

Now draw a chart between :Time on (x-axis) and (P, Np, Wi, Wp) on (y-axis) :

140000000

1500 1480

120000000

1460 100000000 1440 Np, 80000000 Wp, Wi 60000000

1420 Pressure 1400

Np Wp Wi

1380 40000000 1360 20000000 0 1999

1340

2004

2009 Time

2014

Figure 125 Past& Future

174

1320 2019

P

CHAPTER 4

4.4EOR From last study in literature review about types of recovery the best one and most suitable one is the(Polymer Flooding) that will be environmentally and economically good for the reservoir. Using polymers to increase viscosity of water in small bores and making the displacement of oil by water with same rate to not to trap oil So must use special type of polymers: 1. Purely Viscous This type at small diameter Ɣ1 increase water has low viscosity (high speed) so in small pores oil will be trapped that‘s make this type not suitable for use. Ex: a) Poly Socharide (PS). b) Hydroxy Ethyle Celelouse (HEC)

Figure 126Purely Viscous

175

CHAPTER 4

2. Visco Elastic This type is suitable as in small diamter Ɣ1 has high water viscosity (low speed) and In large diamters Ɣ2 has low viscosity (high speed) . Ex: a) Poly Acylamide (PA) b) Poly Ethylene Oxyde (PEO) so by adding visco elastic polymer with optimum concentration make water in large and small diameter move at same velocity.

Figure 127 Visco Elastic

The Viscosity selection The selection of water viscosity that will flood its defends on the condition of the reservoir at moment of flooding and the target required By using (Reservoir management spread sheet) its able to show the behavior of reservoir with different water viscosity and comparing between them.

176

CHAPTER 4

As shown in the following chart Where Visc.1= 0.5 CP, Visc.2= 1 CP & Visc.3= 10 CP From this chart notice that the effect of changing viscosity on production where with increasing water viscosity the result is increasing in cumulative oil produced and retardant of water production

prediction by chemical effect 1.2E+11 1E+11 8E+10 6E+10 4E+10 2E+10 0 0

2E+09

4E+09 time (days) visc. 1

visc. 2

6E+09

visc. 3

Figure 128 prediction by chemical effect

177

8E+09

CHAPTER 4

4.5MBAL 1- Montecarlo Tool

Figure 130 Montecarlo Results 1

Figure 129 Montecarlo Results 2

178

CHAPTER 4

2-MBAL MBE

1- History Matching results : A-Drive mechanism is shown in the figure

Figure 131 Drive mechanism

The figure shows the drive mechanism of the reservoir where it start with fluid expansion with Fluid expansion Pore volume compressibility and water influx with the percentage shown in the figure was the dominated driving mechanism . and at 1985 the water injection was started . B-Bottom drive aquifer

179 Figure 132 Bottom drive aquifer

CHAPTER 4

C-Graphical method graph

Figure 133 graphical method

The Graphical method shows the relationship between (F/Et ) and (We/ Et ) where the intercept is the original oil in place (OOIP ) as shown in the figure = 205.79 MMSTB D-Analytical method graph :

Figure 134 Analytical method

180

CHAPTER 4

Prediction results: 1-average gas and oil rate with time

Figure 135 Gas and oil rate

2-Average water injected with cumulative oil produced

Figure 136 Average water injected with cumulative oil produced

181

CHAPTER 4

3-cumulative gas and oil produced with time

Figure 137 cumulative gas and oil produced

4 - Cumulative oil produced with water injected

Figure 138 Cumulative oil produced with water injected

182

CHAPTER 4

5-water injection And cumulative oil production with time

Figure 139 water injection And cumulative oil production with time

6-oil saturation with time

Figure 140 oil saturation with time

183

CHAPTER 4

7- Oil recovery factor

Figure 141 recovery factor

Recovery factor is 47 % at 1-1-2035

184

CHAPTER 4

4.6 ECLIPSE Results 1- Model Eclipse model the reservoir with its wells in present time and in future till reservoir depletion with different properties.

Figure 142 Reservoir Model

Side view of reservoir with different saturations.

Figure 143 Side view 185

CHAPTER 4

2- GRAPHES a. Total production (Oil, Gas & Water) , total water injection verses Years

Total oil production (FOPT) Total gas production (FGPT) Total water Production (FWPT) Total water injection (FWIT)

Figure 144 FOPT,FGPT, FWPT, FWIT Vs Date

b. Production and injection rates verses date Field Gas Production Rate (FGPR) Field Oil Production Rate (FOPR) Field Water Production Rate (FWPR) Field Water Injection Rate (FWIR)

Figure 145FGPR, FOPR, FWPR, FWIR Vs Date 186

CHAPTER 4

3- Originally In Place Calculations

Figure 146 In place calculation

Eclipse provide report for each year till depletion in the previous report show that:Original Oil In Place 204.653154 MMSTB Original Water In Place 215.737127 MMSTB Original Gas In Place 43664.797 MMSCF

Prediction

187

CHAPTER 4

Recommendation Final Recovery factor can be increase by increasing number of produced wells or increase the injection rate . New produced well in marine zone at cell (9,2) Result recovery factor = .68

Cell(9,2) New produced well

Figure 147 New Well

Increasing number of produced wells in highly oil saturation cells and thick formation will be economically and increasing the recovery factor and have the optimum production

.68 RF 0.63 Series2 Series1 4 no. of wells 3

0

1

2

3

4

Figure 148 Comparison no. of wells

188

5

CHAPTER 4

RF With and Without Injection The following chart shows the importsance of the water injection in the reservoir to increase the recovery factor. So By increasing the injection wells the production increase 70 60

RF %

50 40 Wiyhout inj. 30

With inj.

20 10 0 1

Figure 149 Comparison Inj. Wells

189

CHAPTER 4

Conclusion Based on the case study and the previous explanation, the following can be concluded: MBE by Excel calculations must be used to know the reservoir type and primary reserve estimate. Monte Carlo simulation (probabilistic approach) proved to be more successful in estimating IOIP as it gives all the possible values based on the data available (P10, P50, P90). MBAL Material Balance Tool can be used to confirm the IOIP from Monte Carlo and can also be used to determine the reservoir driving mechanism. ECLIPSE Simulation very useful for model the reservoir , shows the whole parameters of the reservoir with time changing , predict the reservoir behavior with changing conditions .

The summary of IOIP and RF results of the case study can be summarized as follows. Table 50 Conclusion

OOIP RF%

MBE Calculation 205.6 @ 2035 .69

Montecalo 209 Not applicaple

190

MBE MBAL 205.3 .47

ECLIPSE 204 .65

REFERENCES

REFERENCES 1- The Petroleum Society of CIM, Determination of Oil and Gas Reserves, Canada,1994. 2- Repsol YPF, Reserves Reporting System, Louisiana, 2005. 3- Arps,J.J, 1945, Analysis of Decline Curves, Trans. AIME 4- Arps,J.J, 1956, Estimation of primary oil reserves, Trans. AIME 5- Ahmed, Tarek. Reservoir Engineering Handbook. Amsterdam , Elsevier, GPP, 2006.Print. 6- Reservoir Issue 1, part of Reservoir Engineering for Geologists, Fekete, February 2008 7- Schilthius,R., Solution-Gas-Drive Reservoirs, Trans. AIME, 1936, Vol.118. 8- Clark, N., Elements of Petroleum Reservoirs. Dallas, TX:SPE, 1969. 9- Cole, F., Reservoir Engineering Manual, Houston, TX: Gulf Publishing Co., 1969. 10- Havlena, D., and Odeh, A. S., “The Material Balance as an Equation of a Straight. Line,” JPT, August 1963, 11- Havlena, D., and Odeh, A. S., “The Material Balance as an Equation of a Straight Line, Part II—Field Cases,” JPT, July 1963. 12-

Dake, L., The Practice of Reservoir Engineering, Amsterdam: Elsevier. 1994.

13- Dake, L. P., Fundamentals of Reservoir Engineering. Amsterdam: Elsevier. 1978. 14- Van Everdingen, A., and Hurst, W., “The Application of the Laplace Transformation to Flow Problems in Reservoirs,” Trans. AIME, 1949. 15- B.C.Craft, Applied Petroleum Reservoir Engineering,2nd edition ,1991. 16- James J. Sheng,Ph.D.,Modern Chemical Enhanced Oil Recovery Theory and Practices, Elsevier, GPP,2010, Print 17- Sara Thomas , Chemical EOR-The Past, Does It Have A Future , SPE Distinguished Lecturer Series ,2005. 18- George S. Monte Carlo: Concepts, Algorithms, and Applications. New York, Springer, 2008. Print 19- Metropolis, N. and Ulam, S., “The Monte Carlo Method” J. Amer. Stat. Assoc., 1949. 20- “Petroleum Reserves Definitions” published by SPE, 1964. 191

REFERENCES

21- Schlumberger ,Simulation Software Manuals , Eclipse , 2005. 22- Petroleum Expert, MBAL Explanation, www.petex.com/products/?ssi=4 23- Islam Amged Nassar , Reservoir Project , BUE, 2010 24- Petroleum Experts, Reservoir Analytical Simulation , MBAL, version 7 , 2003.

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A study on:Belayim Marine Field ( Zone II)

Submitted to:Natural Gas Engineering Program

i

ii

ACKNOWLEDGMENT

ACKNOWLEDGMENT Thanks and indebtedness is directed first and always to Allah for all his graces, without the power he gave to us , the accomplishment of this work would have been certainly impossible. We would like to extend our deep gratitude and appreciation to our family; for their love, help, understanding and continuous encouragement. We would like to express our deep gratitude, appreciation and sincerest thanks to our professor for his supervision, advices, constructive discussion and great help during the work Professor Doctor Attia M. Attia, our thesis supervisor. Finally, we would like to express our gratitude to our project assistant Eng. Ahmed Rayan who helped us technically and mentally throughout our work period.

iii

Contents

Contents CHAPTER 1 ...................................................................................................................... 1 1.1 Introduction .......................................................................................................................................... 1 Belayim Marine Field (ZoneII) ........................................................................................................ 1 1.2 Objectives ................................................................................................................................................ 4

CHAPTER 2 ...................................................................................................................... 5 2 Literature Review................................................................................................................................... 5 2.1 Reserves Definition .................................................................................................................... 5 2.1.1 SEC Definitions ............................................................................................................... 6 2.1.2 SPE Definitio n s ......................................................................................................... 9 2 . 2 R e s e r v e E s t i m a t i o n M e t h o d s .................................................................................... 12 2.2.1 Analogy:- ...................................................................................................................... 13 2.2.2 Volumetric Method ....................................................................................................... 15 2.2.2.1 Volumetric Uncertainty ....................................................................................... 17 2.2.3 Decline Curve Analysis (DCA): ............................................................................... 18 2.2.4 Material Balance Equation (MBE): .............................................................................. 24 2.2.4.1 MBE Assumptions:............................................................................................. 27 2.2.4.2 Primary Recovery Mechanism ............................................................................. 29 2.2.4.2 .1Rock And Liquid Expansion Drive: ....................................................... 30 2.2.4.2 .2 Depletion Drive: ......................................................................................... 31 2.2.4.2 .3 Gas-Cap Drive: .......................................................................................... 33 2.2.4.2.4 .Water Drive: ............................................................................................. 35 2.2.4.2.5 Gravity Drainage Drive : ............................................................................. 37 2.2.4.2.6 Combination: ............................................................................................. 39 2.2.4.3 Driving Indexes MBE: ........................................................................................ 40 2.2.4.3.1 Depletion Drive Index(Oil Zone Oil Expansion ),(DDI) ...................... 41 2.2.4.3.2Segregation Drive Index (Gas Zone Gas Expansion),(SDI) .................... 41 2.2.4.3.3Water Drive Index (W DI) .......................................................................... 41 2.2.4.3.4Expansion Drive Index (Rock And Liquid), (EDI) .............................. 41 2.2.4.4 MBE In Linear Form: .......................................................................................... 42 2.2.4.4.1 Volumetric Under saturated Reservoir ........................................................ 45 2.2.4.4 .2Volumetric Saturated Reservoirs ........................................................... 47 2.2.4.4 .3 Gas Cap Drive Reservoirs ...................................................................... 48 2.2.4.4 .4 Water Drive Reservoirs ............................................................................ 50 2.2.4.4 .5 Combination Drive Reservoir ............................................................... 57 2.2.4.5 Water Influx[5] .................................................................................................... 59 2.2.4.5 .1 Steady-state method .................................................................................... 59 2.2.4.5.2 VEH unsteady-state method ........................................................................ 61 2.2.4.5.3 Fetkovich Pseudo steady-state method ...................................................... 63 2.3 Enhanced Oil Recovery (EOR) [16,17] ................................................................................... 65 2.3 .1 Miscible EOR ................................................................................................................ 65 iv

Contents

2.3 .2 Chemical EOR ............................................................................................................. 66 2.3.3 Other EOR Processes ................................................................................................... 66 2.3 .2.1 Polymer Flooding ................................................................................................ 69 2.3.2.2 Surfactant Flooding ............................................................................................. 74 2.3 .2.3 Alkaline Flooding ............................................................................................... 75 2.4 Reservoir Simulation ......................................................................................................... 80 2.4.1 MBAL [22] .................................................................................................................... 81 2.4.2 Monte Carlo Simulation .............................................................................................. 83 2.4.3 ECLIPSE Simulation[21] .............................................................................................. 84 2.5 Comparison Between Reserve Estimation Methods[23] .......................................................... 87

CHAPTER 3 .................................................................................................................... 89 3 Methodology..............................................................................................................................................89 3.1 Available Data .......................................................................................................................... 89 3.2 Methodology............................................................................................................................. 92 3.2.1.1 The Material Balance Equation ............................................................................ 93 3.2.1.2 Water Influx ....................................................................................................... 101 3.2.1.2 .1Steady state Water Influx (SS) ................................................................... 101 3.2.1.2 .2 Semi-Steady State For Water Influx (SSS) ............................................... 105 3.2.1.2 .3 Unsteady state (USS) ................................................................................ 110 3.2.1.3 Prediction ........................................................................................................... 116 3.2.2 Reservoir Management Spread sheet ........................................................................... 125 3.2.3MBAL [24] ................................................................................................................... 129 3.2.3.1 Montecarlo Simulation Tool [24] : .................................................................... 129 3.2.3.2 MBE Tool [24] : ................................................................................................ 133 3.2.4 ECLIPSE [21] .............................................................................................................. 149

CHAPTER4 ................................................................................................................... 160 4

Result ..................................................................................................................................................160 4.1PVT Correlations [5] ............................................................................................................... 160 4.2 History Matching .................................................................................................................... 167 4.3 Prediction................................................................................................................................ 172 4.4EOR ......................................................................................................................................... 175 4.5 MBAL .................................................................................................................................... 178 4.6 ECLIPSE Results .................................................................................................................... 179 Conclusion .................................................................................................................................... 189 REFERENCES ............................................................................................................................. 191

v

List of Figures

List of Figures Figure 1 Belayim Marine Oil Location Map . ........................................................................................................... 2 Figure 2 SEC Classification Of Oil And Gas Resources .[2] .................................................................................... 6 Figure 3 SPE Resource Classification System[1] ...................................................................................................... 9 Figure 4 Probabilistic Definition Of Reserves. ........................................................................................................ 10 Figure 5 Classification of production decline curves .[4] ........................................................................................ 19 Figure 6 Exponential, Hyperbolic And Harmonic Approaches . ............................................................................. 22 Figure 7 Decline Curve of an Oil well . [6] ............................................................................................................. 23 Figure 8 (Material Balance Tank Model) ................................................................................................................ 24 Figure 9 Solution Gas Drive Reservoir.[8] .............................................................................................................. 31 Figure 10 Production Data Of Depletion Drive Reservoir. [8] ............................................................................... 32 Figure 11 Gas-cap drive reservoir.[8] ..................................................................................................................... 33 Figure 12 Production Data For A Gas-Cap Drive Reservoir.[8] ............................................................................ 34 Figure 13 Reservoir With Water Drive .[8] ............................................................................................................. 35 Figure 14 Aquifer Geometries . [8].......................................................................................................................... 36 Figure 15 Production Data For A Water Drive Reservoir. [8] ............................................................................... 36 Figure 16 Initial Fluid Distribution In An Oil Reservoir . [8] ................................................................................. 37 Figure 17 Combination Drive Mechanism . [8] ....................................................................................................... 39 Figure 18 Classification Of The Reservoir. [5] ....................................................................................................... 46 Figure 19 Determining N For Saturated Reservoirs . [5] ........................................................................................ 47 Figure 20 F versus Eo + m Eg . [5] ........................................................................................................................ 49 Figure 21(F/Eo) versus (Eg/Eo)............................................................................................................................... 49 Figure 22 (F/Eo) As A Function Of (∆P/Eo) .[5] ..................................................................................................... 52 Figure 23 Steady State Model Applied To MBE.[5] ................................................................................................. 53 Figure 24 Havlena And Odeh Straight Line Plot . [10.11] ....................................................................................... 56 Figure 25 VEH Cylindrical In Shape Reservoir....................................................................................................... 61 Figure 26 Dimensionless Time And Fluid Influx Chart.[5] ..................................................................................... 62 Figure 27 Pressure Steps Used To Approximate The Pressure-Time Curve . [5] .................................................... 63 Figure 28 EOR Injection Method.[17] ..................................................................................................................... 67 Figure 29 Chemical EOR Target In Selected Countries.[17] .................................................................................. 68 Figure 30 Chemical Floods History. [17]................................................................................................................ 68 Figure 31 Current Status World Wide Production World Wide.[17] ....................................................................... 68 Figure 32 Polymer Flood Field Performance .[17] ................................................................................................. 73 Figure 33 Surfactant Flood [17] .............................................................................................................................. 74 Figure 34 pH Values Of Alkaline Solutions .[16] .................................................................................................... 76 Figure 35 Alkaline Flood Field Performance. [17] ................................................................................................. 78 Figure 36 Isopach Contour Map For Net Pay Zone OF Marine Zone 2 . ............................................................... 89 Figure 37 Reservoir MBE . ...................................................................................................................................... 94 Figure 38 Chart Calculate N. ................................................................................................................................ 100 Figure 39 Plot Of Pressure And Pressure Drop Versus Time. [15] ....................................................................... 101 Figure 40 Semi Steady State Behavior . ................................................................................................................ 105 Figure 41 Un Steady State Behavior ..................................................................................................................... 110 Figure 42 Plotting ∑Qt.∆P/Eo Vs (F-Wi*Βw)/EO At Re/Rw =2. .......................................................................... 113 Figure 43 Plotting ∑Qt.∆P/Eo vs (F-Wi*βw)/EO at re/rw =4............................................................................... 113 Figure 44 Plotting ∑Qt.∆P/Eo vs (F-Wi*βw)/EO at re/rw =8............................................................................... 114 Figure 45 Plotting ∑Qt.∆P/Eo vs (F-Wi*βw)/EO at re/rw =6............................................................................... 114 Figure 46 ∑Qt.∆P/Eo At Re/Rw = Infinity............................................................................................................. 115 Figure 47 Chart between P with ( wepe& we uss)) ................................................................................................ 123 Figure 48 Chart Between P With ( Wepe& We Uss)By Using Mew Wi. ................................................................ 124 Figure 49 Predicted p . .......................................................................................................................................... 124 Figure 50 Reservoir Management Spread Sheet Wells Input. ................................................................................ 125

vi

List of Figures

Figure 51Reservoir Management Spread Sheet Pressure Input. ........................................................................... 126 Figure 52 Pressure Matching ................................................................................................................................ 126 Figure 53 Reservoir Management Spread Sheet PVT Input . ................................................................................ 126 Figure 54 Reservoir management spread sheet PVT Matching . ......................................................................... 127 Figure 55 Reservoir Management Spread Sheet Well Locations. .......................................................................... 127 Figure 56 Reservoir Management Spread Sheet Prediction .................................................................................. 128 Figure 57 Reservoir Management Spread Sheet Prediction by chemical effect ..................................................... 128 Figure 58 Choosing Monte Carlo Tool. ................................................................................................................. 129 Figure 59 System Option Window.......................................................................................................................... 130 Figure 60 PVT Menu ............................................................................................................................................. 130 Figure 61 Data Input ............................................................................................................................................. 130 Figure 62 Match PVT data .................................................................................................................................... 131 Figure 63 Selecting Distributions. ......................................................................................................................... 131 Figure 64 Distributions.......................................................................................................................................... 132 Figure 65 General Option Widow. ........................................................................................................................ 134 Figure 66 PVT list ................................................................................................................................................ 135 Figure 67 Black Oil ( Data Input). ......................................................................................................................... 135 Figure 68 PVT Matching. ...................................................................................................................................... 136 Figure 69 Matching. .............................................................................................................................................. 136 Figure 70 Oil FVF Curve...................................................................................................................................... 137 Figure 71 Oil Viscosity Curve............................................................................................................................... 137 Figure 72 GOR Curve. .......................................................................................................................................... 138 Figure 73 Input List. ............................................................................................................................................. 138 Figure 74 Tank Parameters. .................................................................................................................................. 139 Figure 75 Water Influx.......................................................................................................................................... 139 Figure 76 Rock Compressibility............................................................................................................................. 140 Figure 77 Rock Compaction. ................................................................................................................................. 140 Figure 78 Relative Permeability. ........................................................................................................................... 141 Figure 79 Relative Permeability Curves. ............................................................................................................... 141 Figure 80 History Matching Table......................................................................................................................... 142 Figure 81 Import Window. .................................................................................................................................... 142 Figure 82 Import Setup. ........................................................................................................................................ 143 Figure 83 Import file. ............................................................................................................................................. 143 Figure 84 History Matching List........................................................................................................................... 144 Figure 85 Run History Matching. .......................................................................................................................... 144 Figure 86 Analytical Method. ............................................................................................................................... 145 Figure 87 Graphical method.................................................................................................................................. 145 Figure 88 Energy Plot........................................................................................................................................... 146 Figure 89 WD Function Plot.................................................................................................................................. 146 Figure 90 Production Prediction List. ................................................................................................................... 147 Figure 91 Prediction Calculation Setup. ............................................................................................................... 147 Figure 92 Tank Prediction Data. ........................................................................................................................... 148 Figure 93 Run Simulation Window. ....................................................................................................................... 148 Figure 94 Data File Section. .................................................................................................................................. 149 Figure 95 Simulator Preface.................................................................................................................................. 153 Figure 96 Run The Simulator................................................................................................................................. 153 Figure 97 Running The Simulator. ........................................................................................................................ 153 Figure 98 Print File Location. ............................................................................................................................... 154 Figure 99 Original Oil In Place (OOIP)................................................................................................................ 154 Figure 100 Start FLOVIZ ...................................................................................................................................... 154 Figure 101 Run The Model 1 . .............................................................................................................................. 155 Figure 102 Run The Model 3 . .............................................................................................................................. 155 Figure 103 Run The Model 2. ................................................................................................................................ 155 Figure 104 (FLOVIZ Parameters). ........................................................................................................................ 156 Figure 105 Reservoir Model . ............................................................................................................................... 156 Figure 106 RUN OFFICE...................................................................................................................................... 157

vii

List of Figures

Figure 107 Load All Vectors . ................................................................................................................................ 157 Figure 108 Input Variables . .................................................................................................................................. 158 Figure 109 Output OFFICE. ................................................................................................................................. 158 Figure 110 OFFICE Output table.......................................................................................................................... 159 Figure 111 OFFICE Output Charts . .................................................................................................................... 159 Figure 112 Gas Solubility ...................................................................................................................................... 160 Figure 113 Correction..................................................................................................................................... 161 Figure 114 FVF ..................................................................................................................................................... 162 Figure 115 Oil Compressibility ............................................................................................................................. 163 Figure 116 Oil Viscosity ........................................................................................................................................ 164 Figure 117 Crude Oil Denisty................................................................................................................................ 165 Figure 118 Bw ....................................................................................................................................................... 165 Figure 119 Water Compressibility ......................................................................................................................... 166 Figure 121 Gp Vs Years ......................................................................................................................................... 168 Figure 120 Wp,Wi,Np (bbl) Vs Years ..................................................................................................................... 168 Figure 122 Cw,Co,Rs ............................................................................................................................................. 170 Figure 123 Bo, Mo ................................................................................................................................................. 170 Figure 124 re/rw=infinty ....................................................................................................................................... 171 Figure 125 Past& Future....................................................................................................................................... 174 Figure 126Purely Viscous...................................................................................................................................... 175 Figure 127 Visco Elastic ........................................................................................................................................ 176 Figure 128 prediction by chemical effect ............................................................................................................... 177 Figure 129 Montecarlo Results 2 ........................................................................................................................... 178 Figure 130 Montecarlo Results 1 ........................................................................................................................... 178 Figure 131 Drive mechanism ................................................................................................................................. 179 Figure 132 Bottom drive aquifer............................................................................................................................ 179 Figure 133 graphical method................................................................................................................................. 180 Figure 134 Analytical method ................................................................................................................................ 180 Figure 135 Gas and oil rate ................................................................................................................................... 181 Figure 136 Average water injected with cumulative oil produced ......................................................................... 181 Figure 137 cumulative gas and oil produced ......................................................................................................... 182 Figure 138 Cumulative oil produced with water injected ...................................................................................... 182 Figure 139 water injection And cumulative oil production with time .................................................................... 183 Figure 140 oil saturation with time........................................................................................................................ 183 Figure 141 recovery factor .................................................................................................................................... 184 Figure 142 Reservoir Model .................................................................................................................................. 185 Figure 143 Side view ............................................................................................................................................. 185 Figure 144 FOPT,FGPT, FWPT, FWIT Vs Date ................................................................................................... 186 Figure 145FGPR, FOPR, FWPR, FWIR Vs Date .................................................................................................. 186 Figure 146 In place calculation ............................................................................................................................. 187 Figure 147 New Well ............................................................................................................................................. 188 Figure 148 Comparison no. of wells ...................................................................................................................... 188 Figure 149 Comparison Inj. Wells ......................................................................................................................... 189

viii

LIST OF TABLES

List Of Tables Table 1 Classification Of Proved Reserves.[2] .......................................................................................................... 8 Table 2 Historical Development Of Reserves Definitions And Classifications. ........................................................ 11 Table 3 Recovery Factors For Oil And Gas Reservoirs .[2] .................................................................................... 16 Table 4 Decline Curve Equations'. ......................................................................................................................... 21 Table 5 Dimensionless Time And Fluid Influx Table .[5] ........................................................................................ 62 Table 6 Polymer Structures And Their Characteristics.[16] ................................................................................... 70 Table 7 Properties Of Several Common Alkalis .[16].............................................................................................. 77 Table 8 Reserve Estimation Methods Comparison .[23] ......................................................................................... 87 Table 9 Summary Of Reserve Estimation Methods.[23] .......................................................................................... 88 Table 10 Belayim Marine Field (Zone 2) Data........................................................................................................ 90 Table 11 Belayim Marine Field (Zone 2) Pvt Data . ............................................................................................... 91 Table 12 Calculate Oil Compressibility. .................................................................................................................. 96 Table 13 Calculate Water Compressibility . ............................................................................................................ 97 Table 14 Calculate Effective Compressibility. ........................................................................................................ 98 Table 15 Calculate Wi ,Wp,βw . ............................................................................................................................... 98 Table 16 Calculate (Eo)&(F-Wi βw). ...................................................................................................................... 99 Table 17 Marine zone II Data ................................................................................................................................ 103 Table 18 Calculated k' values ................................................................................................................................ 104 Table 19 Determining Semi Steady State Equations’ Parameters ......................................................................... 108 Table 20 Comparing Values Of (Δwe SSS)/ΔT And (Δwe MBE)/ΔT. .................................................................. 109 Table 21 Td vs pressure and Ce. ............................................................................................................................ 112 Table 22 Calculation of ∑Qt.∆P/Eo at re/rw = 2 and 4. ....................................................................................... 113 Table 23 Calculation Of ∑Qt.∆P/Eo At Re/Rw = 6 And 8. .................................................................................... 114 Table 24 Calculating ∑Qt.∆P/Eo At Re/Rw = Infinity. .......................................................................................... 115 Table 25 Prediction Table ..................................................................................................................................... 116 Table 26 3 Pressures Assumption .......................................................................................................................... 116 Table 27 Cw,Co,Ce, βo, βw for P.=1400 ............................................................................................................... 116 Table 28 Cw,Co,Ce, βo, βw for P.=1410 ............................................................................................................... 117 Table 29 Cw,Co,Ce, βo, βw for P.=1420 ............................................................................................................... 117 Table 30 Input Cw,Co,Ce, βo, βw for the 3 P. ....................................................................................................... 117 Table 31Calculate Delta P..................................................................................................................................... 118 Table 32 Calculate TD ........................................................................................................................................... 118 Table 33 Calculate TD at re/rw >10 [5]................................................................................................................ 119 Table 34 Calculate (QT) ........................................................................................................................................ 119 Table 35 Calculate ∑Qt.∆P ................................................................................................................................... 120 Table 36 Input QT ,∑Qt.∆P. .................................................................................................................................. 120 Table 37 Calculate We uss ..................................................................................................................................... 121 Table 38 Input Wp ,NP........................................................................................................................................... 121 Table 39 Calculate Wi ........................................................................................................................................... 122 Table 40 Calculate NP*βo ,WP*βw, WI*βw ,∆P ................................................................................................... 122 Table 41 Calculate N*βoi*Ce*∆P ......................................................................................................................... 122 Table 42 Calculate We MBE .................................................................................................................................. 123 Table 43 crude oil denisty used correletion. .......................................................................................................... 164 Table 44 Oil Denisty suitable Correlation ............................................................................................................. 164 Table 45 PVT Conculosion .................................................................................................................................... 166 Table 46 History Matching. ................................................................................................................................... 167 Table 47 PVT Matching. ........................................................................................................................................ 169 Table 48 Wi/Np & dWi/Np ..................................................................................................................................... 172 Table 49 Prediction Calculation ............................................................................................................................ 173 Table 50 Conclusion .............................................................................................................................................. 190

ix

LIST OF TABLES

x

CHAPTER 1

CHAPTER 1 1.1 Introduction Belayim Marine Field (ZoneII) Zone II is one of the oil reservoirs composing Belayim Marine field; from the stratigraphic point of view, it belongs to the upper portion of Belayim formation. Zone II was discovered by 113M-1 in 1962 and production started in 1963 through wells 113M-1 & BM2, by Dec. 1996, Zone II had produced a cum. of 6.75*106 STD m3 of oil and the production rate was 526 STD m3/d. The geological structure of Zone II that was reconstructed based composed of sand bodies mainly deposited in the west-southwest flank of an anticline with a north-west southeast trend. The sand thickness reduces along the crest of the structure and is interrupted by a fault along the west flank. Two aquifers have been identified based on the different original OWC depths. The OWC of the main aquifer is identified based on the log analysis of well 113M-25, the secondary aquifer is present only in an isolated area and well 113M-31 identified it. The oil characteristics were determined based on the analysis of the surface sample collected at well 113M-26; it points out a mediumhigh density oil of 20.7 API.

1

CHAPTER 1

Balayim Marine Oil Field – Location map

CHAPTER 1

Figure 1 Belayim Marine Oil Location Map .

2

CHAPTER 1

This book starts with showing the project objectives to be a good reservoir engineer and whats the purpose of reservoir engineering and what is reservoir engineer concerns. Then talking about literature review about reservoir engineering which used to build knowledge about types of reservoirs, driving mechanisms and different types of reserve calculation. Then starts to show the available data that will be used in calculations and starts it in methodology that shows the procedures followed in calculation to get final results Finally the book shows the final results and conclusion of different calculations type and compare between results to get the best one and build recommendations to increasing the recovery factor and productivity

3

CHAPTER 1

1.2 Objectives From Reservoir Engineering Concepts Starting The Main Project Objectives:1- Selecting the most suitable correlations to calculate fluid properties of (Belayim Marine Field (ZoneII)) with lowest

23-

45-

average absolute error(AAE) to helping and decrease money paid in core analysis and PVT Lab. Knowing the reservoir type and its driving mechanism. Calculating the original oil in place (OOIP) by using different methods e.g.(MBE, Montecarlo , Decline curve, MBAL ,Eclipse) , compare between those methods and choose the most accurate result. Predicting of the reservoir life and production rate with highest recovery factor. Enhancing oil recovery method to increase oil production and decrease water cut percentage.

4

CHAPTER 2 2 Literature Review 2.1 Reserves Definition Unfortunately, there are some disagreements in the world related to reserve definition. While some countries base their reserves on maximum recoverable, others rely on minimum recoverable. Many countries tend to maximize their reserves for political and economic reasons and keep their reserves confidential. So it is very difficult to estimate the world reserves, not only for the disagreements in definitions but also for the lack of data and incorrect aggregation. The problem of definitions is being solved over the years by applying standard definitions. The most common definitions used globally are those set by SPE and The US Securities and Exchange Commission (SEC).

5

2.1.1 SEC Definitions According to the US Securities and Exchange Commission (SEC), Oil and Gas resources are classified according to the flow chart shown in Figure

Figure 2 SEC Classification Of Oil And Gas Resources .[2]

The total oil and gas resources are the total quantities expected to be present underground, this can be divided into discovered resources and undiscovered resources. Undiscovered resources are those quantities not yet discovered. Discovered resources are those resources already discovered using existing technology. They can be classified into recoverable and unrecoverable resources. Unrecoverable resources are those quantities that cannot be recovered due to lack of technology or economic reasons. Recoverable resources are those quantities that can be recovered using existing technology and current economic conditions. They can be further classified into reserves and cumulative production.

Cumulative production is the quantities already produced from known accumulation s using the existing technology and under current economic conditions. 6

Reserves are estimated volumes of crude oil, condensate, natural gas, natural gas liquids, and associated substances anticipated to be commercially recoverable from known accumulations from a given date forward, under existing economic conditions, by established operating practices, and under current government regulations. Reserve estimates are based on geologic and/or engineering data available at the time of estimate. The relative degree of an estimated uncertainty is reflected by the categorization of reserves as either "proved" or "unproved" Proved Reserves can be estimated with reasonable certainty to be recoverable under current economic conditions. Current economic conditions include prices and costs prevailing at the time of the estimate. Reserves are considered proved if the commercial productivity of the reservoir is supported by actual engineering tests. By using probabilistic approach, if the probability that the real production will have a chance of 90% to exceed or be equal to the calculated value, we consider the estimated value as proved reserves. Proved reserves can be further classified as shown in Figure 2. Unproved Reserves are based on geological and/or engineering data similar to those used in the estimates of proved reserves, but when technical, contractual, economic or regulatory uncertainties preclude such reserves being classified as proved. They may be estimated assuming future economic conditions different from those prevailing at the time of the estimate.. Unproved reserves may further be classified as probable and possible.

7

Probable Reserves (P50) are less certain than proved reserves and can be estimated with a degree of certainty sufficient to indicate they are more likely to be recovered than not. By using probabilistic approach, the chance of the real production figure to be equal to or exceed the calculated value is 50%, we usually refer to it as proved plus probable reserves and are given by (P50). Possible Reserves are less certain than proved reserves and can be estimated with a low degree of certainty, insufficient to indicate whether they are more likely to be recovered than not Table 1 Classification Of Proved Reserves.[2]

PDP are those quantities expected to be recovered from locations where a proper field development plan was introduced, wells were drilled, and production is on-going. PDNP are those quantities expected to be recovere3d from locations where a proper field development plan was introduced, wells were drilled, but production has not yet started. PUD are those quantities that in order to be recovered, the accumulation sin which they exist need a proper development plan to take place in order to decide the number of wells needed And other requirement for these quantities to be produced and the field to be productive.

8

2.1.2 SPE Definitions Figure 4 presents the petroleum resource classification according to Society of Petroleum Engineers (SPE) and its similarity to the SEC resource classification

.

Figure 3 SPE Resource Classification System[1]

Discovered Petroleum-initially-in-place is that quantity of petroleum which is estimated, on a given date, to be contained in known accumulations, plus those quantities already produced therefrom. This may be may be subdivided into Commercial and Sub-commercial categories, with the estimated potentially recoverable portion being classified as Reserves and Contingent Resources respectively. Reserves are defined as those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. The uncertainty in reserve estimation can be reflected in proved. Probable, and possible reserves. Proved, probable and possible reserves have the same definitions of the SEC classification. The probabilistic approach is best explained in figure 4. 9

.

Figure 4 Probabilistic Definition Of Reserves.

Contingent Resources are those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from known accumulations, but which are not currently considered to be commercially recoverable. Undiscovered Petroleum-initially-in-place is that quantity of petroleum which is estimated, on a given date, to be contained in accumulations yet to be discovered. Prospective Resources are those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from undiscovered accumulations Many governments, organisations and companies have made their own reserves definitions and classifications. The complete historical development of reserves definitions and classifications is shown in table 2.

10

Table 2 Historical Development Of Reserves Definitions And Classifications. Society of Petroleum Engineers (SPE) Date 1964

Other Organizations

Definition SPE Reserves Definitions [20]

Organization Name

Date

American Petroleum

1936

Institute Reserves Definition (API) [27] 1981

SPE, WPC, AAPG [21]

ARPS Reserve

1962

Classification [28] October, 1988

SPE Reserves Definitions [22]

McKelvey Resource

1972

Classification System [29] March, 1997

SPE/ WPC [23]

SEC Reserve

1975

Classification [30] February,

SPE/WPC/AAPG [24]

Norwegian Petroleum Directorate (NPD) [31]

2000 2001

Guidelines for the Evaluation

The UNFC

of Petroleum Reserves and

Classification System

Resources, 2001 2005

[25]

2001

November 2003

[32]

Glossary of Terms Used in Petroleum Reserves/Resources Definitions [26]

Chinese Classification System [33]

11

2005

2 . 2 Reserve Estimation Methods Reserves can be calculated using the following techniques[2] :Analogy Volumetric Decline curve analysis Material Balance Reservoir simulation Two calculation approaches can be applied. These are deterministic and probabilistic approaches. The deterministic approach involves using a single value from each input parameter of the equation used in the estimation process. This generates a single value for the IOIP. This approach is used when uncertainty is low or when the degree of confidence in the data available is very high. The probabilistic approach involves making a probability distribution function for each input parameter using the range of uncertainty in each parameter (minimum, maximum, average). This distribution function allows the calculation of all the possible outcomes of the IOIP value and covers all the ranges of uncertainty. This approach I used when the uncertainty is very high and can be also used as a risk analysis method.

12

2.2.1 Analogy:Reserves are estimated by analogy to reservoir in the same geographic area or field with similar properties. The SEC institute that only offset wells in the same field can be used to estimate proved reserves by analogy. Nevertheless, analogy is most used to determine probable and possible reserves in the same geographic area. The similarities between the target reservoir and the analogy model should include :• Lithology and depositional environment of the reservoir rock • Petrophysical parameters of the rock and fluid saturations • Initial bottom hole pressure (BHP) and temperature (BHT) • BHP at the start-up of a project • Reservoir fluid properties (PVT) • Structural configuration • Reservoir heterogeneity and continuity • Recovery mechanism, natural or induced • Well spacing and spacing pattern

Reservoir maturity and the stage of development of both the analogy and the target reservoir should be taken into account. When the proper analogy has been established, it can be used to estimate[2]: • Ultimate recovery per well • Drainage area and appropriate well spacing • Initial reservoir parameters • Initial productivity per well • Typical decline type and decline characteristics • Expected abandonment pressure • Expected drive mechanism 13

• Enhanced recovery factor for pressure maintenance • Recovery for a given drive mechanism: − Per well − Per acre-foot (RF) The analogy method is applied by comparing the following factors for the analogous and current fields or wells: 1. Recovery Factor (RF), 2. Barrels per Acre-Foot (BAF). 3. Estimated Ultimate Recovery (EUR). The RF of a close-to-abandonment analogous field is taken as an approximate value for another field. Similarly, the BAF is assumed to be the same for the analogous and current field or well, which is calculated by the following equation

14

2.2.2 Volumetric Method The volumetric technique is the most widely used approach to estimate reserves during the exploration stage of a field. Often used as first step, it is compared with other techniques as more data become available and the uncertainty decrease. The estimate ultimate recovery (EUR) for an oil reservoir is given by:

Where:N = oil in place (STB) RF = Recovery factor Vb = Bulk reservoir volume (acre ft) Ø = Average reservoir porosity Sw = Average reservoir water saturation Bo = Oil formation volume factor (RB/STB)

From a contour map:

where Vb = contour interval Ao = area of the contour Using reservoir drainage area and thickness:-

Where: A = reservoir area (acres) h = thickness (ft)

15

Table 3 (gives the typical primary recovery factors for oil and gas reservoirs by drive mechanism. The primary oil driving mechanisms will be discussed in the Material balance equation section .

Table 3 Recovery Factors For Oil And Gas Reservoirs .[2]

16

2.2.2.1 Volumetric Uncertainty A volumetric estimate provides a static measure of oil or gas in place. The accuracy of the estimate depends on the amount of data available, which is very limited in the early stages of exploration and increases as wells are drilled and the pool is developed. Monte Carlo simulation provides a methodology to quantify the uncertainty in the volumetric estimate based on assessing the uncertainty in input parameters such as: • Gross rock volume, reservoir geometry and trapping • Pore volume and permeability distribution • Fluid contacts

The accuracy of the reserve or resource estimates also increases once production data is obtained and performance type methods such as material balance and decline analysis can be utilized. Finally, integrating all the techniques provides more reliable answers than relying solely on any one method

17

2.2.3 Decline Curve Analysis (DCA): Production decline analysis is a basic tool for forecasting production from a well or a group of wells once there is sufficient production to establish a decline trend as a function of time or cumulative production. The technique is more accurate than volumetric methods when sufficient data is available to establish a reliable trend and is applicable to both oil and gas wells. It is most often used to estimate remaining recoverable reserves, but it is also useful for water flood and enhanced oil recovery (EOR) performance assessments and in identifying production issues/mechanical problems. Production decline analysis of an analogous producing pool provides a basis for forecasting production and ultimate recovery from an exploration prospect or stepout drilling location. A well‘s production capability declines as production proceeds. This happens mainly due to combination of pressure depletion, displacement of another fluid (gas and/or water) and changes in relative fluid permeability. Plots of production rate versus production history (time or cumulative production) illustrate declining production rates as cumulative production increases. In theory, production decline analysis is only applicable to individual wells but in practice extrapolations of group production trends often provide acceptable approximations for group performance. The estimated ultimate recovery (EUR) for a producing unit is obtained by extrapolating the trend to an economic production limit. The extrapolation is valid provided that [3]: • Past trends were developed with the well producing at capacity. • Volumetric expansion was the primary drive mechanism. The technique is not valid when there is significant pressure support from an underlying aquifer. • The drive mechanism and operating practices continue into the future.

18

Curves that can be used for production forecasting include: 1. Production rate versus time. 2. Production rate versus cumulative production. 3. Water cut percentage versus cumulative production 4. Water level versus cumulative production 5. Cumulative gas versus cumulative oil 6. Pressure versus cumulative production.

Figure 5 shows the classification of production decline curves and how each of them can be applied by using exponential, hyperbolic and harmonic approaches.[4]

Figure 5 Classification of production decline curves .[4]

19

The first two types are the most common types of decline curves, because the trend for wells producing from conventional reservoirs under primary production will be ―exponential‖ ,which means that the data will present a straight line trend when production rate vs. time is plotted on a semi-logarithmic scale. The data will also present a straight line trend when production rate versus cumulative production is plotted on regular Cartesian coordinates. The well‘s ultimate production volume can be read directly from the plot by extrapolating the straight line trend to the production rate economic limit. Arps (1945, 1956) developed the initial series of decline curve equations to model well performance [3]. The equations were initially considered as empirical and were classified into (Exponential, Hyperbolic, Harmonic), based on the value of the exponent ―b‖ that characterizes the change in production decline rate with the rate of production. For exponential decline ‗b‘=0, for hyperbolic ‗b‘ is generally between 0 and 1. Harmonic decline is a special case of hyperbolic decline where ‗b‘=1. Table 4 summarizes ARPS‘ equation used in DCA.

20

Table 4 Decline Curve Equations'.

Figure 6 shows the difference between the exponential, hyperbolic, and harmonic approaches used in DCA (rate versus time). [5]

21

Figure 6 Exponential, Hyperbolic And Harmonic Approaches .

22

Chapter 2

Figure7 is an example of a typical oil well showing the difference between Exponential and Harmonic Extrapolations (rate versus cumulative production) and also shows the economic limit at which data are extrapolated. [6]

Figure 7 Decline Curve of an Oil well . [6]

In Figure 7, the Exponential extrapolation yields a straight line, while the Harmonic extrapolation yielded a concave upward shape (curve). This is due to the difference in the exponent ‗b‘ values for both methods. The economic limit line is the line showing the economic production limit at which the data are extrapolated in order to predict future production.

23

Chapter 2

2.2.4 Material Balance Equation (MBE): Material balance is the technique that uses the law of conservation of matter. The material balance method is a tank model equation. It is written from start of production to any time (t) as the expansion of oil in the oil zone plus the expansion of gas in the gas zone plus the expansion of connate water in the oil and gas zones plus the contraction of pore volume in the oil and gas zones plus the water influx plus the water injected plus the gas injected equal to the oil produced plus the gas produced plus the water produced.[5] Figure 8 shows the tank model on which MBE was built.

Figure 8 (Material Balance Tank Model)

A general material balance equation that can be applied to all reservoir types was first developed by Schilthuis in 1936 [7]. Although it is a tank model equation, it can provide great insight for the practicing reservoir Engineer.

24

Chapter 2

It is written from start of production to any time (t) as follows: Expansion of oil in the oil zone + Expansion of gas in the gas zone + Expansion of connate water in the oil and gas zones + Water influx + Water injected + Gas injected = Oil produced + Gas produced + Water produced The Generalized MBE can be written mathematically as:

Where: N = initial oil in place, STB Np = cumulative oil produced, STB G = initial gas in place, SCF Gi = cumulative gas injected into reservoir, SCF Gp = cumulative gas produced, SCF We = water influx into reservoir, bbl Wi = cumulative water injected into reservoir, STB Wp = cumulative water produced, STB Bti = initial two-phase formation volume factor, bbl/STB = Boi Boi = initial oil formation volume factor, bbl/STB 25

Chapter 2

Bgi = initial gas formation volume factor, bbl/SCF Bt = two-phase formation volume factor, bbl/STB = Bo + (Rsoi - Rso)Bg Bo = oil formation volume factor, bbl/STB Bg = gas formation volume factor, bbl/SCF Bw = water formation volume factor, bbl/STB Big = injected gas formation volume factor, bbl/SCF Biw = injected water formation volume factor, bbl/STB Rsoi = initial solution gas-oil ratio, SCF/STB Rso = solution gas-oil ratio, SCF/STB Rp = cumulative produced gas-oil ratio, SCF/STB Cf = formation compressibility, psia-1 Cw = water isothermal compressibility, psia-1, Swi = initial water saturation, Δpt = reservoir pressure drop, psia = pi - p(t) p(t) = current reservoir pressure, psia

26

Chapter 2

2.2.4.1 MBE Assumptions: The MBE keeps an inventory on all material entering, leaving, or accumulating within a region over discrete periods of time during the production history. The calculation is most vulnerable to many of its underlying assumptions early in the depletion sequence when fluid movements are limited and pressure changes are small. Uneven depletion and partial reservoir development compound the accuracy problem. The basic assumptions in the MBE are as follows [5]:Constant temperature: Pressure–volume changes in the reservoir are assumed to occur without any temperature changes. If any temperature changes occur, they are usually sufficiently small to be ignored without significant error. Reservoir characteristics: The reservoir has uniform porosity, permeability, and thickness characteristics. In addition, the shifting in the gas–oil contact or oil–water contact is uniform throughout the reservoir. Fluid recovery: The fluid recovery is considered independent of the rate, number of wells, or location of the wells. The time element is not explicitly expressed in the material balance when applied to predict future reservoir performance. Pressure equilibrium: A uniform pressure is assumed to apply across the pool. The model is considered as a tank with infinite permeability. Constant reservoir volume: Reservoir volume is assumed to be constant except for those conditions of rock and water expansion or water influx that are specifically considered in the equation. Reliable production data: There are essentially three types of production data that must be recorded in order to use the MBE in performing reliable reservoir calculations. These are: 1. Oil production data, even for properties not of interest, can usually be obtained from various sources and is usually fairly reliable. 2. Gas production data is becoming more available and reliable as the market value of this commodity increases; unfortunately, this data will often be more questionable where gas is flared.

27

Chapter 2

3. The water production term need represent only the net withdrawals of water; therefore, where subsurface disposal of produced brine is to the same source formation, most of the error due to poor data will be eliminated.

28

Chapter 2

2.2.4.2 Primary Recovery Mechanism The overall performance of oil reservoirs is greatly affected by the nature of energy (driving mechanism), responsible for moving the oil to the well bore. There are basically six driving mechanisms which are [5] :1. Rock and Liquid expansion drive. 2. Depletion drive. 3. Gas-cap drive. 4. Water drive. 5. Gravity drainage drive. 6. Combination drive.

29

Chapter 2

2.2.4.2 .1Rock And Liquid Expansion Drive: An under-saturated reservoir is a reservoir that initially exists at a pressure higher than its bubble point pressure. At pressures above the bubble point pressure, crude oil, connate water and rock are the only materials present. As the reservoir pressure declines (with production), the rock and fluids expand due to their compressibilities. This compressibility is due to the expansion of individual rock grains and formation compaction. As a result of this expansion, the pore volume will be reduced as a result of a decrease in fluid pressure. This reduction in pore volume will force the crude oil and water out of the pore volume to the wellbore which explains this driving mechanism. The reservoirs under this driving mechanism, usually has a constant gas oil ratio. This driving mechanism is considered the least efficient driving force and has the lowest oil recovery rates.

30

Chapter 2

2.2.4.2 .2 Depletion Drive: This mechanism is also referred to as: Solution gas drive Dissolved gas drive Internal gas drive In this type of reservoir, the major source of energy us a result of gas liberation from the crude oil and the subsequent expansion of the solution gas as the reservoir pressure is reduced. As pressure falls below bubble point pressure, gas bubbles are liberated; these bubbles expand and force the crude oil out of the pore space as shown in figure 9.

Figure 9 Solution Gas Drive Reservoir.[8]

Cole (1969), suggested that a depletion drive reservoir can be identified by the following characteristics:[9] 1)

Reservoir pressure declines rapidly and continuously

2)

Gas Oil ratio increases to maximum ad then declines

3)

Water production is absent or negligible

4)

Well behavior: requires pumping at early stage

5)

Oil recovery ranges from 8% to 25%

31

Chapter 2

The above characteristic trends occurring during the production life of depletion drive reservoirs is shown in figure 10.

Figure 10 Production Data Of Depletion Drive Reservoir. [8]

32

Chapter 2

2.2.4.2 .3 Gas-Cap Drive: Gas-cap drive reservoirs can be identified by the presence of a gas cap with little or no water drive as shown in figure 11.

Figure 11 Gas-cap drive reservoir.[8]

The natural energy available to produce the crude oil comes from: The expansion of the gas cap The expansion of solution gas as it is liberated

Cole and Clark (1969), suggested that gas-cap drive reservoirs have the following characteristics [9]: 1)

Reservoir pressure falls slowly and continuously

2)

Gas Oil ratio rises continuously

3)

Water production is absent or negligible

4)

Well behavior: gas-cap drive reservoirs tend to flow longer than depletion drive reservoirs

5)

Oil recovery ranges from 20% to 40%

33

Chapter 2

The above characteristic trends occurring during the production life of gascap drive reservoirs is shown in figure 12 .

Figure 12 Production Data For A Gas-Cap Drive Reservoir.[8]

34

Chapter 2

2.2.4.2.4 .Water Drive: any reservoirs are bounded on a portion or all of their edges by water bearing rocks called aquifers. The aquifers may be so large compared to the reservoir where they act infinitely. They may also range down to small (almost negligible), in their effects on the reservoir performance. The aquifer may be entirely bounded by impermeable rock so that the reservoir and aquifer together form a volumetric (closed unit). On the other hand, the reservoir may be outcropped at one or more places where it may be replenished by surface water as shown in figure 13.

Figure 13 Reservoir With Water Drive .[8]

When talking about water influx, it is common to speak about edge water and bottom water drive. Bottom water occurs directly beneath the oil and edge water occurs in the flanks at the edge of the oil as shown in figure 14 . Regardless of the source of water, the water drive mechanism is the result of water moving into the pore spaces originally occupied by oil, replacing the oil and displacing it to the producing wells.

35

Chapter 2

Figure 14 Aquifer Geometries . [8]

Cole (1969), suggested that water drive reservoirs have the following characteristics [11]: 1)

Reservoir pressure remains high

2)

Gas Oil ratio remains low

3)

Water production starts early and increase to appreciable amounts

4)

Well behavior: flow until water production gets excessive

5)

Oil recovery ranges from 20% to 55%

Figure 15 shows the production data for a water drive reservoir.

Figure 15 Production Data For A Water Drive Reservoir. [8]

36

Chapter 2

2.2.4.2.5 Gravity Drainage Drive : The mechanism of gravity drainage occurs in petroleum reservoirs as a result of differences in densities of the reservoir fluids. The effects of gravitational forces can be simply illustrated by placing a quantity of crude oil and a quantity of water in a jar and agitating the contents. After agitation, the jar is placed at rest, and the denser fluid (normally water) will settle to the bottom of the jar, while the less dense fluid (normally oil) will rest on top of the denser fluid. The fluids have separated as a result of the gravitational forces acting on them. The fluids in petroleum reservoirs have all been subjected to the forces of gravity, as evidenced by the relative positions of the fluids, i.e., gas on top, oil underlying the gas, and water underlying oil. The relative positions of the reservoir fluids are shown in Figure 16 .

Figure 16 Initial Fluid Distribution In An Oil Reservoir . [8]

Gravity segregation of fluids is probably present to some degree in all petroleum reservoirs, but it may contribute substantially to oil production in some reservoirs.

37

Chapter 2

Cole (1969), stated that reservoirs under gravity drainage drive have the following characteristics [9] :1)

Reservoir pressure has variable rates of pressure decline depending on the amount of gas. In most cases, there is a rapid pressure decline.

2)

Gas Oil ratio remains low.

3)

Water production starts is absent or negligible.

4)

Oil recovery ranges from 30% to 70%.

38

Chapter 2

2.2.4.2.6 Combination: In real cases, a reservoir usually includes at least two main drive mechanisms. For instance, in the case shown in the figure below, the management of the reservoir for different drive mechanisms can be diametrically opposed (e.g. low perforation for gas cap reservoirs compared with high perforation for water drive reservoirs). If both occur as in Figure, a compromise must be required, and this compromise must take into account the strength of each drive present, the size of the gas cap, and the size/permeability of the aquifer. It is the job of the reservoir manager to identify the strengths of the drives as early as possible in the life of the reservoir to optimize the reservoir performance.

Figure 17 Combination Drive Mechanism . [8]

39

Chapter 2

2.2.4.3 Driving Indexes MBE: As discussed earlier, oil can be primarily recovered by five driving mechanisms, to determine the relative magnitude of each of these driving mechanisms, the compressibility term in the general material balance equation is neglected and the equation is rearranged as follows:

Dividing by the right hand side of the equation gives:

The terms on the left hand side of equation above represent the depletion drive index (DDI), the segregation drive (gas cap drive) index (SDI), and the water drive index (WDI) respectively. The expansion drive index (EDI), has a minor effect on the oil recovery and can be neglected (not included in the equation). Prison‘s abbreviation can be used to give the following equation [7] : DDI + SDI+ WDI+ EDI + 1 Where EDI can be neglected as mentioned earlier.

The driving index for each mechanism can be calculated for a reservoir in order to calculate the efficiency of each driving mechanism.

40

Chapter 2

2.2.4.3.1

Depletion Drive Index(Oil Zone Oil Expansion ),(DDI)

Depletion drive is the oil recovery mechanism wherein the production of the oil from its reservoir rock is achieved by the expansion of the original oil volume with all its original dissolved gas.

2.2.4.3.2

Segregation Drive Index (Gas Zone Gas Expansion),(SDI)

Segregation drive (gas cap drive) is the mechanism wherein the displacement of oil from the formation is accomplished by the expansion of the original free gas cap.

2.2.4.3.3

Water Drive Index (W DI)

Water drive is the mechanism wherein the displacement of the oil is accomplished by the net encroachment of water into the oil zone.

2.2.4.3.4

Expansion Drive Index (Rock And Liquid), (EDI)

For under saturated oil reservoirs with no water influx, the principle source of energy is a result of the rock and fluid expansion. Where all the other three driving mechanisms are contributing to the production of oil and gas from the reservoir, the contribution of the rock and fluid expansion to the oil recovery is too small and essentially negligible and can be ignored.

41

Chapter 2

2.2.4.4 MBE In Linear Form: Normally, when using the material balance equation, each pressure and the corresponding production data is considered as being a separate point from other pressure values. From each separate point, a calculation is made and the results of these calculations are averaged. However, a method is required to make use of all data points with the requirement that these points must yield solutions to the material balance equation that behave linearly to obtain values of the independent variable. The straight- line method was developed by Havlena and Odeh (1963) by starting with[10,11] :

Defining the ratio of the initial gas cap volume to the initial oil volume as:

Putting m in the equation gives:

42

Chapter 2

Let:

Where: F = Underground withdrawal Eo = Oil and Dissolved gas expansion terms Eg = Gas cap expansion term Ef,w = rock and water compression/expansion terms So we obtain:

(E1)

The above equation was developed in order to determine the following three unknowns [10,11] 1. The Original Oil in Place N 2. The cumulative water influx We 3. The original gas cap size compared to the oil zone size m.

43

Chapter 2

The straight line relationship developed by Havlena and Odeh can be used in the following six applications:

Case 1: Determination of N in volumetric undersaturated reservoirs Case 2: Determination of N in volumetric saturated reservoirs Case 3: Determination of N and m in gas cap drive reservoirs Case 4: Determination of N and We‖ in water drive reservoirs Case 5: Determination of N, m, and We in combination drive reservoirs Case 6: Determination of average reservoir pressure, p

In this study, the main aim is to calculate the IOIP (N), and so the first five cases will be considered for calculating N only.

44

Chapter 2

2.2.4.4.1 Volumetric Under saturated Reservoir For a volumetric under-saturated reservoir, the conditions associated with a driving mechanism are [5]: • We = 0, since the reservoir is volumetric • m = 0, since the reservoir is undersaturated • Rs = Rsi = Rp, since all produced gas is dissolved in the oil Applying the above condition to Equation (E1) gives:

(E2)

Or

0

(E2)

To calculate N, a plot of (F/ Eo+ Ef ,w) versus cumulative production Np is 0 plotted. Figure shows an example of this plot. Dake (1994) suggest that this plot can take two shapes [12]. As shown in figure 9, Line A implies that the reservoir is a volumetric reservoir. This defines a purely depletion drive reservoir whose energy drives solely form the expansion of rock, connate water and oil. Lines B and C, implies the existence of a water drive in which the reservoir was energized by water influx, Line B represents a moderate aquifer whose degree of energizing decreases with time. While, Line c represents a strong aquifer who is acting infinitely. In all cases, IOIP (N) is the ordinate value of the plateau as shown in figure 18.

45

Chapter 2

Figure 18 Classification Of The Reservoir. [5]

46

Chapter 2

2.2.4.4 .2Volumetric Saturated Reservoirs A saturated oil reservoir is an oil reservoir that originally exists at its bubble point pressure (Pb). The main driving mechanism in saturated reservoirs results from the liberation and expansion of the solution gas as the pressure drops below bubble point pressure. Havlena and Odeh equation (Equation (E1)) can be written as [10, 11]:

(E3) Assuming that the water and rock expansion term Ef,w is negligible in comparison with the expansion of solution gas. This relationship can be used to determine N for saturated reservoirs by plotting F versus Eo. This should result in a straight line going through the origin with a slope of N as shown in figure 19.

Figure 19 Determining N For Saturated Reservoirs . [5]

47

Chapter 2

2.2.4.4 .3 Gas Cap Drive Reservoirs In gas cap reservoirs, the expansion of the gas-cap gas is the dominant driving mechanism and assuming that natural water influx is negligible (We=0), the Havlena and Odeh MBE (Equation (E1)) can be written as:

(E4) The way in which equation (E4) is applied depends on the number of unknowns in the equation, there are three possible unknowns in equation (E4). N is unknown, m is known. M is unknown, N is known. N and m are unknown. The first and last case will be considered, because in the second case, N is known ,and as mentioned earlier; only methods to determine N will be discussed.

Unknown N, Known m: Equation 3 indicates that when m is known, a plot of F versus (Eo + m Eg) on a Cartesian scale would produce a straight line through the origin with a slope of N as shown in figure 20.

48

Chapter 2

Figure 20 F versus Eo + m Eg . [5]

N and m are unknown: If both N and m are unknown, equation (E4) can be re-expressed as:

(E5) A plot of F/Eo versus Eg/Eo should be linear with intercept N and slope mN as shown in figure 21.

Figure 21(F/Eo) versus (Eg/Eo). 49

Chapter 2

2.2.4.4 .4 Water Drive Reservoirs Dake (1978) points out that the term Ef,w can be neglected in water drive reservoirs. And so equation (E1) can be written as [13]: (E6) If, the reservoir has no initial gas cap, equation (E6) can be re-written as: (E7) Dake (1978) points out that in attempting to use the above two equations to match the production and pressure history of a reservoir, the greatest uncertainty is always the determination of the water influx (We) [13]. In fact, in order to calculate the influx the engineer is confronted with what is inherently the greatest uncertainty in the whole subject of reservoir engineering. The reason is that the calculation of (We) requires a mathematical model which itself relies on the knowledge of aquifer properties. Three water influx models will be discussed. These models are: Pot aquifer model Schilthuis steady-state model. Van Everdingen- Hurst unsteady state model. The assumed reservoir for these models will be a water drive reservoir with no gas cap which is represented by the following equation: (E8)

50

Chapter 2

Pot-Aquifer model: The pot aquifer model is used to represent water influx and is summarised by the following equation (E8)

(E9) The aquifer properties cw, cf, h, ra, and θ are rarely available and they can be combined as one unknown (K) and so equation (E9) can be written as: (E10) Combining equations (E8) and (E10) gives:

(E11)

Equation (E11) implies that a plot of (F/Eo) as a function of (∆P/Eo) would yield a straight line with an intercept of N and slope of K as shown in figure 22. 51

Chapter 2

Figure 22 (F/Eo) As A Function Of (∆P/Eo) .[5]

Schilthuis steady-state model: The steady state aquifer model was proposed by Schilthuis (1936) is given by [11]:

(E12) 52

Chapter 2

Combining equation (E8) with equation (E12) gives:

(E13) Plotting F/Eo versus

results in a straight line with an intercept N and

a slope (C) that describes the water influx as shown in figure 23.

Figure 23 Steady State Model Applied To MBE.[5]

53

Chapter 2

Van Everdingen - Hurst unsteady state model: The Van Everdingen-Hurst unsteady state model is given by [14]:

(E14)

With:

Van Everdingen and Hurst presented the dimensionless water influx WeD as a function of the dimensionless time tD and dimensionless radius rD that are given by:

Combining equation (E8) with (E14) gives:

(E14) 54

Chapter 2

The proper methodology of solving the above linear relationship is summarized in the following steps. Step 1. From the field past production and pressure history, calculate the underground withdrawal F and oil expansion Eo. Step 2. Assume an aquifer configuration, i.e., linear or radial. Step 3. Assume the aquifer radius ra and calculate the dimensionless radius rD. Step 4. Plot (F/Eo) versus (Σ Δp WeD)/Eo on a Cartesian scale. If the assumed aquifer parameters are correct, the plot will be a straight line with N being the intercept and the water influx constant B being the slope. It should be noted that four other different plots might result. These are: • Complete random scatter of the individual points, which indicates that the calculation and/or the basic data are in error. • A systematically upward curved line, which suggests that the assumed aquifer radius (or dimensionless radius) is too small. • A systematically downward curved line, indicating that the selected aquifer radius (or dimensionless radius) is too large. • An s-shaped curve indicates that a better fit could be obtained if a linear water influx is assumed.

Figure 24 shows a schematic illustration of Havlena-Odeh (1963) methodology in determining the aquifer fitting parameters [10,11].

55

Chapter 2

Figure 24 Havlena And Odeh Straight Line Plot . [10.11]

56

Chapter 2

2.2.4.4 .5 Combination Drive Reservoir The general straight line MBE equation is illustrated in equation E1 and is given by:

(E1) Where:

Havlena and Odeh differentiated equation (E1) with respect to pressure and rearranged the equation to eliminate m to give [10, 11]:

(E15) Where:

57

Chapter 2

A plot of the left-hand side of equation (E15) versus the second term on the right for a selected aquifer model should, if the choice is correct, provide a straight line with unit slope whose intercept on the ordinate gives the initial oil in place, N. After determining N and We, equation (E1) can be used to solve directly for m.

The derivatives used in equation (E15) can be evaluated numerically by any finite difference technique including forward , backward and central techniques.

58

Chapter 2

2.2.4.5 Water Influx[5] Many reservoirs are bounded on a portion or all their perimeters by water bearing rocks – aquifers. As reservoir fluids are produced, a pressure differential develops between the surrounding aquifer and the reservoir. The aquifer reacts by encroaching across the original hydrocarbon-water contact. Aquifers retard pressure decline in reservoirs by providing a sourceof water influx We. We is a function of time (production). We is dependent on the size of aquifer and the pressure drop from the aquifer to the reservoir.

2.2.4.5 .1 Steady-state method Schilthuis Steady-state method is the simplest model for water influx. Water influx is proportional to the pressure drawdown (pi – p):

Integrating Eq gives Where: k′= water flux constant, bbl/day-psi P = pressure at the original oil-water contact pi= initial pressure at the external boundary of the aquifer.

Calculation of k′and Wefrom production data: In a reasonably long period, if the production rate and reservoir pressure remain substantially constant, there is:

59

Chapter 2

The equation can be rearranged to:

If the pressure stabilizes and the withdraw rates are not reasonably constant, water influx in the pressure stabilized period Δt can be calculated from the total productions of oil, gas and water within Δt:

Then k′can be found from the following equation:

For an under-saturated oil reservoir and at pressures higher than the bubble point pressure, Equation can be simplified to:

60

Chapter 2

2.2.4.5.2 VEH unsteady-state method Van Everdingen and Hurst solutions to the single-phase unsteady state flow equation are used to calculate water influx. The hydrocarbon reservoir is the inner boundary condition and is analogous to the well and the aquifer is the flow medium analogous to the reservoir. Properties of aquifer are assumed homogeneous and constant. Reservoir and aquifer are assumed cylindrical in shape.

Figure 25 VEH Cylindrical In Shape Reservoir.

Water flux is calculated by the following equations:

In Where WeD is given as a function of dimensionless time D t and dimensionless radius D r (see Tables 5and Figures 26):

The dimensionless time and dimensionless radius are defined as

61

Chapter 2

Figure 26 Dimensionless Time And Fluid Influx Chart.[5]

Table 5 Dimensionless Time And Fluid Influx Table .[5]

62

Chapter 2

Values for Δpj are determined from measure pressures. The pressure changes are calculated as follows to approximate the pressure-time curve:

Figure 27 Pressure Steps Used To Approximate The Pressure-Time Curve . [5]

2.2.4.5.3 Fetkovich Pseudo steady-state method The size of the aquifer is known-finite aquifer. Any water influx from the aquifer depletes the pressure accordingto the material balance equation. Steps of calculation of water influx by using Fetkovich Pseudo steady state method: 1. Calculate the initial encroachable water, Wei(in bbls), in the aquifer

63

Chapter 2

2. Calculate the productivity index, J, for flow from the aquifer to the reservoir a) For finite aquifer with no flow at the outer boundary:

b) For finite aquifer with constant pressure the outer boundary:

3. Calculate the average reservoir pressure during a time step:

4. Calculate the water influx during a time step

5. Calculate the total cumulative water influx at the current time

6. Calculate the average aquifer pressure at the end of the current timestamp

7. Repeat Steps 3 to 6 for next time step. 64

Chapter 2

2.3 Enhanced Oil Recovery (EOR) [16,17] The life of an oil well goes through three distinct phases where various techniques are employed to maintain crude oil production at maximum levels. The primary importance of these techniques is to force oil into the wellhead where it can be pumped to the surface. Techniques employed at the third phase, commonly known as Enhanced Oil Recovery (EOR), can substantially improve extraction efficiency. Laboratory development of these techniques involves setups that duplicate well and reservoir conditions. Core Flooding Pumps or Core Analysis Pumps, such as Teledyne Isco Syringe Pumps, are used in laboratory testing of these Enhanced Oil Recovery (EOR) techniques.

The Three Stages of Oil Field Development Primary Recovery : In Primary Recovery, oil is forced out by pressure generated from gas present in the oil. Secondary Recovery : In Secondary Recovery, the reservoir is subjected to water flooding or gas injection to maintain a pressure that continues to move oil to the surface. Tertiary Recovery : Tertiary Recovery, also known as Enhanced Oil Recovery (EOR), introduces fluids that reduce viscosity and improve flow. These fluids could consist of gases that are miscible with oil (typically carbon dioxide), steam, air or oxygen, polymer solutions, gels, surfactant-polymer formulations, alkalinesurfactant-polymer formulations, or microorganism formulations.

2.3 .1 Miscible EOR Commonly applied in West Texas, this method usually employs supercritical CO2 to displace oil from a depleted oil reservoir with suitable characteristics (typically containing ―light‖ oils). Through changes in pressure and temperature, carbon dioxide can form a gas, liquid, solid, or supercritical fluid. When at or above the critical point of pressure and temperature, supercritical CO2 can maintain the properties of a gas while having the density of a liquid. Injected miscible CO2 will mix thoroughly with the oil within the reservoir such that the interfacial tension between these two substances effectively disappears. CO2 can also improve oil recovery by dissolving in, swelling, and reducing the viscosity of oil.

65

Chapter 2

In deep, high-pressure reservoirs, compressed nitrogen has been used instead of CO2. Hydrocarbon gases have also been used for miscible oil displacement in some large reservoirs. CO2, nitrogen, hydrocarbon gases, and flue gases have also been injected to immiscibly displace oil. At one extreme of conditions, these displacements may simply amount to ―pressure maintenance‖ in the reservoir (a secondary recovery process). Depending on oil character, gas composition and pressure, and temperature, the displacements could have a range of efficiencies up to and approaching a miscible displacement. CO2 has also been injected in a ―huff ‗n puff‖ or cyclic injection mode, like cyclic steam injection.

2.3 .2 Chemical EOR Three chemical flooding processes include polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer (ASP) flooding. In the polymer flooding method, water-soluble polymers increase the viscosity of the injected water, leading to a more efficient displacement of moderately viscous oils. Addition of surfactant to the polymer formulation may, under very specific circumstances, reduce oil-water interfacial tension to almost zero—displacing trapped residual oil. Although no large-scale surfactant-polymer floods have been implemented, the process has considerable potential to recover oil. A variation of this process involves addition of alkaline to the surfactant-polymer formulation. For some oils, alkaline may convert some acids within the oil to surfactants that aid oil recovery. The alkaline may also play a beneficial role in reducing surfactant retention in the rock. For all chemical flooding processes, inclusion of a viscosifier (usually a water-soluble polymer) is required to provide an efficient sweep of the expensive chemicals through the reservoir. Gels are also often used to strategically plug fractures (or other extremely permeable channels) before injecting the relatively expensive chemical solutions, miscible gases, or steam.

2.3.3 Other EOR Processes Over the years, a number of other innovative EOR processes have been conceived, including injection of carbonated water, microorganisms, foams, alkaline (without surfactant), and other formulations. These methods have shown varying degrees of promise, but require additional development before such applications will become common. 66

Chapter 2

Figure 28 EOR Injection Method.[17]

In our case we will focus in chemical EOR Why we use chemical EOR? Conventional oil RF 10) :By using

Interpolation: Table 33 Calculate TD at re/rw >10 [5]

Table 34 Calculate (QT)

7) Then Calculate ∑Qt.∆P :

119

CHAPTER 3

Table 35 Calculate ∑Qt.∆P

Then put the final result

Table 36 Input QT ,∑Qt.∆P.

120

CHAPTER 3

8) Calculate We uss

Table 37 Calculate We uss

9) Calculate NP :

Enter Wp Values : Table 38 Input Wp ,NP

10)

Calculate Wi :

―Assume this const. Until We USS curve intercepts with We MBE curve‖ ―

‖ 121

CHAPTER 3

First assume it = 1 Table 39 Calculate Wi

11) Calculate NP*βo ,WP*βw, WI*βw ,∆P( ) Table 40 Calculate NP*βo ,WP*βw, WI*βw ,∆P

12) Calculate : N*βoi*Ce*∆P Table 41 Calculate N*βoi*Ce*∆P

122

CHAPTER 3

13) Calculate We MBE :

Table 42 Calculate We MBE

14) Draw a Chart Between P with ( WE MBE& WE USS) :

Figure 47 Chart between P with ( wepe& we uss))

15) Change the value of the const. Until We uss intercepts with We mbe Const. Should be less than 2.5 At const. = 1.2992 the 2 curves are intercepted

123

Millions

CHAPTER 3 3.93 3.92 3.91 3.9 We uss

3.89

me

3.88 3.87 3.86 1395

1400

1405

1410 P

1415

1420

1425

Millions

Figure 48 Chart Between P With ( Wepe& We Uss)By Using Mew Wi. 3.93 3.92 3.91 3.9 uss 3.89

mbe

3.88 3.87 3.86 1395 1400 1405 1410 1415 1420 1425

Figure 49 Predicted p .

16) Get the P. at the intercept P. = 1416 17) Repeat these steps for every 2 years until : NP/Wi = 2.5 Then the prediction stops .

124

CHAPTER 3

3.2.2 Reservoir Management Spread sheet It‘s an Excel sheet depends on mathematical calculation by using Microsoft Macros to calculate reservoir engineering purpose. The benefits of using Reservoir Management Spread sheet

Interpolate the PVT data to match data with reservoir pressure. Draw Production History Matching Curve. Reservoir Production Prediction. Comparing the production will be with changing water viscosity by (Polymer Flooding).

The Required Data

Start of Production date . Initial pressure . Reservoir Area and hight. Number and names of wells , wells types (production or injection), wells location and initial flow rate per day PVT data from lab or by correlations at different pressures. Reservoir pressure for each well along production history. Injection water viscosity.

Steps:1- Insert wells information.

Insert initial pressure and starting of production date Insert well name, Type and initial flow rate in bbl/day

Figure 50 Reservoir Management Spread Sheet Wells Input.

125

CHAPTER 3 2-

Press (Pressure Matcher) to insert wells pressures along production history.

Figure 51Reservoir Management Spread Sheet Pressure Input.

3- Press (MATCH) to history matching the pressure with time.

Figure 52 Pressure Matching

4- From Fig.53 press (PVT LAB MATCHER) to insert pvt lab data and start to match the data with different reservoir pressure.

Figure 53 Reservoir Management Spread Sheet PVT Input .

126

CHAPTER 3

5- Press (GO TO LAB) to start matching the PVT data with wells pressure.

Figure 54 Reservoir management spread sheet PVT Matching .

6- From Fig. 55 press (PREDICTION) , Insert (Wells locations, Reservoir area, Height , Initial injection water viscosity and injection water with polymers viscosity) then press (Predict).

Figure 55 Reservoir Management Spread Sheet Well Locations.

127

CHAPTER 3

7- The following fig shows the prediction of the production of the reservoir.

Figure 56 Reservoir Management Spread Sheet Prediction

8- The following fig showing prediction of reservoir production behavior at initial injection water viscosity and changing in water viscosity.

Figure 57 Reservoir Management Spread Sheet Prediction by chemical effect

128

CHAPTER 3

3.2.3MBAL [24] 3.2.3.1 Montecarlo Simulation Tool [24] : The tool enable the user to perform statistical evaluation of reservoir .distribution can be assigned to variable like porosity or thickness of reservoir and the program will generate the range of probability associated with reserve range. Decline Curve Analysis : Production data can be fitted to Hyperbolic , exponential or Hermic decline . these is can be the extrapolation in future for generation forecasts. Software steps: 1-Choose Mote Carlo Tool From Tool Manu As Shown:

Figure 58 Choosing Monte Carlo Tool.

129

CHAPTER 3

2- Defining the general option :

Figure 59 System Option Window

3- enter the PVT fluid properties data form PVT menu :

Figure 60 PVT Menu

4- then enter the data required in the new window as shown :

Figure 61 Data Input 130

CHAPTER 3

5-Match PVT data :

Figure 62 Match PVT data

6- Then choose Distribution from Input menu:

Figure 63 Selecting Distributions.

131

CHAPTER 3

7- Entre the required data in the window where the bulk volume is calculated from reservoir geology information :

Figure 64 Distributions.

8- Then press ― Calc ― , to watch the results .

132

CHAPTER 3

3.2.3.2 MBE Tool [24] :

Data loading History matching Prediction Field development planning using MBE will be applied using MBAL software, the workflow can be divided into:

1. Data loading: This step is the initial step of the development process. In this stage, the available data of the reservoir is loaded into the software, and the general options of the model are determined. These data include: i. Fluid properties ii. PVT properties iii. Estimation of the IOIP from the results of Eclipse simulation results. iv. Production start date. v. Petro-physical data vi. Relative permeability data. vii. Historical data (production and pressure) After loading the data, matching process should be applied for the fluid properties and PVT data as discussed earlier in the volumetric method. The main output of this step is the relative permeability plot and the cumulative oil production and pressure plot.

133

CHAPTER 3

2. History matching: History matching process involves matching the historical data with the data predicted by the model. 3. Model validation: Before using the model for any future prediction, the model‘s ability to predict the past performance in agreement with the input data must be checked. In order to check the model, the model is run on prediction from the start till the end data of the input data. A plot of the cumulative production and historical pressure can be constructed to compare the input data with the prediction data, if the values match; then the model is ready for the prediction process. 4. Prediction: After making sure that the model is valid for prediction, we have to define the target and constraints for the prediction and then check the reservoir behavior under different scenarios.

Software step: 1. Data loading Defining model general options

Figure 65 General Option Widow.

134

CHAPTER 3

Fluid properties From PVT list , choosing fluid properties

Figure 66 PVT list .

Then data would be entered

Figure 67 Black Oil ( Data Input).

135

CHAPTER 3

Then match the data by using Match button and input the data in the table

Figure 68 PVT Matching.

Then click Match and choose data which will match on such as (Bubble point , Gas oil ratio , Oil FVF and Oil Viscosity ) as shown and press Calc button

Figure 69 Matching.

136

CHAPTER 3

Then click Plot button to plot the matched data graphs as shown in the figure :

1-Oil FVF

Figure 70 Oil FVF Curve.

2-oil viscosity

Figure 71 Oil Viscosity Curve.

137

CHAPTER 3

3- Gas Oil Ratio

Figure 72 GOR Curve.

Reservoir parameters The next step is to define the tank (reservoir parameters which include the estimation of the IOIP , average petro-physical data (porosity, water saturation), the relative permeability data, and production history. Figure 73 shows the determination of tank parameters From Input choose Tank Data

Figure 73 Input List.

138

CHAPTER 3

1-Input tank parameters as shown :

Figure 74 Tank Parameters.

2-the water influx of the aquifer was defined using Van EverdingenHurst model discussed earlier in the literature review section as shown:

Figure 75 Water Influx.

139

CHAPTER 3

3-Then enter the rock compressibility by correlation as shown

Figure 76 Rock Compressibility.

4-Enter the rock compaction reversible as shown :

Figure 77 Rock Compaction. 140

CHAPTER 3

5- Relative permeability from tables

Figure 78 Relative Permeability.

The plots of permeability

Figure 79 Relative Permeability Curves.

141

CHAPTER 3

6- production History

Figure 80 History Matching Table.

input the production history by using Import will appear

Figure 81 Import Window.

142

a new window

CHAPTER 3

Choose ―Browse‖ and identify the file location then choose " done " in the new window choose ― Tab Delimited ― then choose "done "

Figure 82 Import Setup.

choose data shown with given field names

Figure 83 Import file. 143

CHAPTER 3

2- History matching Click on the History Matching button then choose Run Simulation to run the simulation

Figure 84 History Matching List.

In the new window click Clac button

\

Figure 85 Run History Matching.

144

to start calculation

CHAPTER 3

Then choose : 1- Analytical method :

Figure 86 Analytical Method.

2-Graphical method :

Figure 87 Graphical method. 145

CHAPTER 3

3- energy plot :

Figure 88 Energy Plot.

4-WD function plot :

Figure 89 WD Function Plot.

146

CHAPTER 3

4-prediction : The main objective of this study is the identification and evaluation of the remaining potential in existing producing zones.

Prediction steps : 1-choose production prediction from prediction set up :

Figure 90 Production Prediction List.

2-entire the data required as shown

Figure 91 Prediction Calculation Setup. 147

CHAPTER 3

3- then choose prediction and constrains and enter the required data

Figure 92 Tank Prediction Data.

4-Then run the simulation and click Calc

Figure 93 Run Simulation Window. 148

CHAPTER 3

3.2.4 ECLIPSE [21] As shown in the literature review before the importance of using software or especially simulators, Here starts to know the steps of using the Reservoir Simulation (ECLIPSE).

ECLIPSE Data File Its consist of eight sections each section specialized in a specific data to input in it as shown:

Figure 94 Data File Section.

Start the Data Input Open New Text pad file and start input data sections

1- RUNSPEC The RUNSPEC section is the first section of an ECLIPSE data input file. It contains the run title, start date, units, various problem dimensions (numbers of blocks, wells, tables etc.), The RUNSPEC section must always be present. 149

CHAPTER 3

The used data code :( TITLE, START, DIMENS, OIL, GAS, WATER, DISGAS, FIELD,EQLDIMS ,TABDIMS, WELLDIMS, AQUDIMS) each of this data code require a specific data, ECLIPSE Manual must had used for helping what this codes needs.

2- GRID The GRID section determines the basic geometry of the simulation grid and various rock properties (porosity, absolute permeability, net-to-gross ratios) in each grid cell. From this information, the program calculates the grid block pore volumes, mid-point depths and inter-block transmissibilities. The actual keywords used depend upon the use of the radial or cartesian geometry options. The program accepts the radial form in a cartesian run and vice versa, but issues a warning.

The used data code :(TOPS,DX, DY, DZ, PERMX, PERMY, PERMZ, PORO, NTG, GRIDFILE, INIT, NOECHO, PINCH).

3- EDIT The EDIT section contains instructions for modifying the pore volumes, block center depths, transmissibilities, diffusivities, and nonneighbor connections (NNCs) computed by the program from the data entered in the GRID section. It is entirely optional.

150

CHAPTER 3

4- PROPS Tables of properties of reservoir rock and fluids as functions of fluid pressures, saturations and compositions (density, viscosity, relative permeability, capillary pressure, etc.). Contains the equation of state description in compositional runs.

The used data code :(SWFN, SGFN, SOF3, ROCK, DENISITY, PVDG, PVTO, PVTW, AQUATAB)

5- REGIONS ` Empty, because this section used for divide the reservoir in different regions and different properties.

6- SOLUTION The SOLUTION section contains sufficient data to define the initial state (pressure, saturations, compositions) of every grid block in the reservoir .

The used data code :(EQUIL, RSVD, RPTRST, RPTSOL)

7- SUMMARY Specification of data to be written to the Summary file after each time step. Necessary if certain types of graphical output (for example watercut as a function of time) are to be generated after the run has finished. If this section is omitted no Summary files are created.

151

CHAPTER 3

The used data code :(RPTONLY, DATE, EXCEL, SEPARATE, ELAPSED, FOIP, FOPR, FOPRH,FOPT,FOPTH,FLPR,FLPRH,FLPT,FLPTH,GOPR,GOPRH, GOPT,GOPTH,GWPR,GGPR,WOPR,WOPRH,WOPT,WOPTH, WWPR,WWPRH,WGPR,WGPRH,FWPR,FWPRH,FWCT,FWCTH, FWPT,FWPTH,GWPR,GWPRH,GWCT,GWCTH,GWPT,GWPTH, WWPRH,WWCTH,WWPT,WWPTH,FGIP,FGPR,FGPRH,FGOR, FGORH,FGPT,FGPTH,RGIP,GGPR,GGPRH,GGOR,GGORH,GGPT, GGPTH,WGPR,WGPRH,WGOR,HWGPT,WGPTH,FPR,RPR,WBHP, WBP5,WBP9,WBHPH,WPI,WPIH,FAQR,FOEW,ROEW,TCPU, WMCTL,WLPR,WLPRH,WPR,AAQR,FAQR,FAQT, AAQP,FOPV,FWPV, WLPT, WLPTH, WWIR,WWIT, FWIR, FWIT,WPI, WBP9)

8- SCHEDULE Specifies the operations to be simulated (production and injection controls and constraints) and the times at which output reports are required. Vertical flow performance curves and simulator tuning parameters may also be specified in the SCHEDULE section.

The used data code :(WELSPECS, COMPDAT, WCONPROD)

WCONHIST,

WCONINJE,

DATES,

After Input the reservoir Data in the Data File, Starting the next step that‘s running the simulation

152

CHAPTER 3

Running the Simulator:1- From the Program Launcher ballet press ECLIPSE

Figure 95 Simulator Preface.

2- Browsing computer drivers to select input data file and press RUN

Figure 96 Run The Simulator.

3- Running the Simulator till end and having confirmation that there is no warning massages or errors

Figure 97 Running The Simulator.

153

CHAPTER 3

4- After running to show the calculation of OOIP, open the file (.PRT) from input folder and search for OOIP

Figure 98 Print File Location.

Figure 99 Original Oil In Place (OOIP).

5- Showing the Model, From Program Launcher select (FLOVIZ)

Figure 100 Start FLOVIZ 154

CHAPTER 3

6- After pressing (RUN), FILEOPENECLIPS

Figure 101 Run The Model 1 .

Figure 103 Run The Model 2.

Figure 102 Run The Model 3 .

155

CHAPTER 3

Figure 105 Reservoir Model .

7- (GRID PROPERTEY ) Button enable to show the different properties required and response of model with TIME factor, that can be selected from (PLAY,PAUSE, …ETC. ) Buttons which at the top bar of the software.

Figure 104 (FLOVIZ Parameters).

156

CHAPTER 3

To get the last report and drawing the curves of different requirements from production rates (Gas, Oil & Water) along reservoir life from the beginning till the predicted depletion, Select from program Launcher (OFFICE).

Figure 106 RUN OFFICE.

8- Select REPORTFILEOPEN VECTORS.

SUMMERY

Figure 107 Load All Vectors .

157

LOAD

ALL

CHAPTER 3

9- At (INPUT), select the vectors required to plot or shown in the output file then press (GENERATE REPORT) .

Figure 108 Input Variables .

10- To see the report Press (OUTPUT) then select showing it as table or Plot as required.

Figure 109 Output OFFICE.

158

CHAPTER 3

Figure 110 OFFICE Output table.

Figure 111 OFFICE Output Charts .

11- Finally, may have more than one plot and different vectors as required.

159

CHAPTER 4

CHAPTER4 4 Result 4.1 PVT Correlations [5] Gas Solubility (Rs) The used correlations : Standing‘s Glaso‘s

Gas Solubility 200 180 160 140 120 Rs 100 80 60 40 20 0

Actual Modified Rs Glaso Standin 0

2000 4000 Pressure

6000

Figure 112 Gas Solubility

The Best and suitable correlation was (Standing correlation) with Average Absolute Error (AAE%) = 50.98 %

x= 0.0125 API - 0.00091(T - 460)

the modified correlation

160

CHAPTER 4

Gas Specific gravity From knowing the gas specific gravity in the separator enabling to calculate the gas specific gravity in different reservoir conditions by adding the factor Delta (∆) from the followed chart. 0.2 0.1 0 ∆ -0.1

0

100

200

300

400

500

600

700

800

-0.2 -0.3 ∆= -6E-15 Poly. (p,delta)

p,delta

P5

Figure 113

p + 1E-11 P4 - 9E-09P3 + 1E-06P2 + 0.001P - 0.255 R² = 1

Correction.

At known pressure -15

∆= (-6×10

5

-11

P )+(10

4

-9

3

-6

2

P )-(9×10 P )+(10 P )+(.001P)-.255

=

±(∆)

Formation Volume Factor (Bo) The used correlatins:Above Bubble Point Pressure (Calhoun's correlation) Calhoun's correlation

161

CHAPTER 4

Below Bubble Point Pressure Standing's correlation Glaso‘s Correlation The Vasquez-Beggs Correlation Standing's correlation

Glaso’s Correlation

The Vasquez-Beggs Correlation

The Suitable Correlation where

PPb Calhoun's correlation Petrosky-Farshad Correlation Chew-Connally PPb Vasquez-Beggs

166

50.98 ---1.282454 1.033 19.11 2.972 0.946866842 8.28

CHAPTER 4

4.2 History Matching Table 46 History Matching.

∆t days

Date

T press,psi year

t days

NP (bbl)

Oct-63

1963

3550

0

Dec-63

1963

3500

60.8

60.8

131161.4

36833.19739

69.18792

0

Dec-65

1965

3110

730

790.8

1594203

457607.4514

1012.66

0

Dec-67

1967

2860

730

1521

2258608

690542.993

1320.86

0

Dec-69

1969

2695

730

2251

2874789

906562.8094

1346.02

0

Dec-71

1971

2555

730

2981

3360180

1057850.842

3943.711

0

Dec-73

1973

2415

730

3711

4553037

1338178.666

6660.91

0

Dec-75

1975

2275

730

4441

4595367

1347607.682

6660.91

0

Dec-77

1977

2165

730

5171

4595367

1347607.682

6660.91

0

Dec-79

1979

2055

730

5901

5856330

1793137.517

9315.21

0

Dec-81

1981

1970

730

6631

7480535

2408742.788

97529.81

0

Dec-83

1983

1860

730

7361

11147941

3251562.624

124991.1

0

Dec-85

1985

1805

730

8091

17339241

4279254.74

593802.2

912552.4

Dec-87

1987

1695

730

8821

21990877

5659457.859

1791955

5727963

Dec-89

1989

1665

730

9551

27760281

7581882.371

3303377

9440997

Dec-91

1991

1600

730

10281 32935028

8540004.594

5576024

11020377

Dec-93

1993

1525

730

11011 37532647

9438303.772

7078767

18805440

Dec-95

1995

1470

730

11741 41055155

10393282.99

8506195

27964291

Dec-97

1997

1390

730

12471 43656149

10987734.77

9514156

33643078

Dec-99

1999

1335

730

13201 45965899

11659207.85

10828708

38510358

Dec-01

2001

1335

730

13931 51218395

12879859.3

12529240

47821449

Dec-03

2003

1350

730

14661 56173602

14039769.53

14640220

65198390

Dec-05

2005

1360

730

15391 60766000

15604244.58

17798347

78063401

Oct-07

2007

1390

669.2

16060 64211703

16789192.91

21056041

91329803

167

GP(MMSCF) WP(bbl) WI(bbl)

CHAPTER 4

Millions

NP

WP

WI

Pressure

100

4000 3500

80 3000

Wp,Wi,Np (bbl)

60

40

2000

Pressure

2500

1500 20 1000 0 1960

1965

1970

-20

1975

1980

1985

1990

1995

2000

2005

2010500 0

time (YEARS)

18

4000

16

3500

14

3000

Gp(MSCF)

12 2500 10 2000 8 1500 6 1000

4

500

2 0 1960

1970

1980 1990 Time(years)

Figure 121 Gp Vs Years

168

2000

0 2010

Pressure(PSIA)

Millions

Figure 120 Wp,Wi,Np (bbl) Vs Years

GP(MMSCF) press,psi

CHAPTER 4

PVT Matching

Table 47 PVT Matching.

169

CHAPTER 4

Cw, Co, Rs 200

0.000014

180

0.000012

160 0.00001

140 120

0.000008

100 0.000006

80 60

0.000004

40 0.000002

20 0 0

500

1000

1500

Pb

2000 Rs

2500 Co

3000

3500

0 4000

Cw

Figure 122 Cw,Co,Rs

1.18

5 4.9

1.175 4.8 1.17

4.7 4.6

1.165 4.5

Bo 1.16

4.4

Bo

4.3

Mo

1.155 4.2 1.15 0

500

1000

1500

Pb

2000 P

2500

Figure 123 Bo, Mo

170

3000

3500

4.1 4000

Undersaturated Oil Reservoir

Active Bottom water Drive

Aquifer State

Driving Mechanism

Reservoir Type

CHAPTER 4

Unsteady state with infinity Aquifer Boundary

Reservoir type: under saturated reservoir with active water drive Aquifer type: Unsteady state with infinite Aquifer boundary OOIP=205749458 STB

Millions

(F-Wi.Bw)/Eo

re/rw=infinty 300 250 200 150 re/rw=infint y

100 50 0 0

10

20

30

40 Millions

∑Qt.∆P/Eo

Figure 124 re/rw=infinty

171

Linear (re/rw=infin ty)

CHAPTER 4

4.3 Prediction The project gets the prediction from ends of available data times : 2009, 2011, 2013, 2015, 2017, 2019 get Wi/Np and then ΔWi/Np as shown :

Table 48 Wi/Np & dWi/Np

ΔWI/NP

Time

WI/NP

2009

1.2992

2011

1.326

0.0268

2013

1.3524

0.0264

2015

1.3775

0.0251

2017

1.4021

0.0246

2019

1.4265

0.0244

172

CHAPTER 4

Then get (avg: ΔWI/NP) which equals = 0.0253625

Table 49 Prediction Calculation T

NP

NP/N

WP

WI

WI/NP

WI/VP

2009

68000000

0.330497555

22157428

88345600

1.2992

0.223612

2011

72000000

0.349938587

24905428

95472000

1.326

0.241649

2013

76000000

0.36937962

27813428

102782400

1.3524

0.260153

2015

80000000

0.388820652

30881428

110200000

1.3775

0.278927

2017

84000000

0.408261685

34109428

117776400

1.4021

0.298104

2019

88000000

0.427702718

37497428

125532000

1.4265

0.317734

2021

92000000

0.44714375

41045428

133571350

1.451863

0.338082

2023

96000000

0.466584783

44753428

141813600

1.477225

0.358944

2025

100000000

0.486025816

48621428

150258750

1.502588

0.38032

2027

104000000

0.505466848

52649428

158906800

1.52795

0.402209

2029

108000000

0.524907881

56837428

167757750

1.553313

0.424612

2031

112000000

0.544348913

61185428

176811600

1.578675

0.447528

2033

116000000

0.563789946

65693428

186068350

1.604038

0.470958

2035

120000000

0.583230979

70361428

195528000

1.6294

0.494901

2037

124000000

0.602672011

75189428

205190550

1.654763

0.519358

2039

128000000

0.622113044

80177428

215056000

1.680125

0.544328

2041

132000000

0.641554076

85325428

225124350

1.705488

0.569812

2043

136000000

0.660995109

90633428

235395600

1.73085

0.59581

2045

140000000

0.680436142

96101428

245869750

1.756213

0.622321

2047

144000000

0.699877174

1.02E+08

256546800

1.781575

0.649346

2049

148000000

0.719318207

1.08E+08

267426750

1.806938

0.676884

2051

152000000

0.73875924

1.13E+08

278509600

1.8323

0.704936

2053

156000000

0.758200272

1.2E+08

289795350

1.857663

0.733501

2055

160000000

0.777641305

1.26E+08

301284000

1.883025

0.76258

2057

164000000

0.797082337

1.32E+08

312975550

1.908388

0.792172

2059

168000000

0.81652337

1.39E+08

324870000

1.93375

0.822278

2061

172000000

0.835964403

1.46E+08

336967350

1.959113

0.852898

2063

176000000

0.855405435

1.53E+08

349267600

1.984475

0.884031

2065

180000000

0.874846468

1.6E+08

361770750

2.009838

0.915678

2067

184000000

0.894287501

1.67E+08

374476800

2.0352

0.947838

2069

188000000

0.913728533

1.74E+08

387385750

2.060563

0.980512

173

CHAPTER 4

Then predict that : The reservoir Abundant time is 2069 as : NP/N =0.913728533 and WI/VP=0.980512 and this is the maximum acceptable values for each of them !!

Now draw a chart between :Time on (x-axis) and (P, Np, Wi, Wp) on (y-axis) :

140000000

1500 1480

120000000

1460 100000000 1440 Np, 80000000 Wp, Wi 60000000

1420 Pressure 1400

Np Wp Wi

1380 40000000 1360 20000000 0 1999

1340

2004

2009 Time

2014

Figure 125 Past& Future

174

1320 2019

P

CHAPTER 4

4.4EOR From last study in literature review about types of recovery the best one and most suitable one is the(Polymer Flooding) that will be environmentally and economically good for the reservoir. Using polymers to increase viscosity of water in small bores and making the displacement of oil by water with same rate to not to trap oil So must use special type of polymers: 1. Purely Viscous This type at small diameter Ɣ1 increase water has low viscosity (high speed) so in small pores oil will be trapped that‘s make this type not suitable for use. Ex: a) Poly Socharide (PS). b) Hydroxy Ethyle Celelouse (HEC)

Figure 126Purely Viscous

175

CHAPTER 4

2. Visco Elastic This type is suitable as in small diamter Ɣ1 has high water viscosity (low speed) and In large diamters Ɣ2 has low viscosity (high speed) . Ex: a) Poly Acylamide (PA) b) Poly Ethylene Oxyde (PEO) so by adding visco elastic polymer with optimum concentration make water in large and small diameter move at same velocity.

Figure 127 Visco Elastic

The Viscosity selection The selection of water viscosity that will flood its defends on the condition of the reservoir at moment of flooding and the target required By using (Reservoir management spread sheet) its able to show the behavior of reservoir with different water viscosity and comparing between them.

176

CHAPTER 4

As shown in the following chart Where Visc.1= 0.5 CP, Visc.2= 1 CP & Visc.3= 10 CP From this chart notice that the effect of changing viscosity on production where with increasing water viscosity the result is increasing in cumulative oil produced and retardant of water production

prediction by chemical effect 1.2E+11 1E+11 8E+10 6E+10 4E+10 2E+10 0 0

2E+09

4E+09 time (days) visc. 1

visc. 2

6E+09

visc. 3

Figure 128 prediction by chemical effect

177

8E+09

CHAPTER 4

4.5MBAL 1- Montecarlo Tool

Figure 130 Montecarlo Results 1

Figure 129 Montecarlo Results 2

178

CHAPTER 4

2-MBAL MBE

1- History Matching results : A-Drive mechanism is shown in the figure

Figure 131 Drive mechanism

The figure shows the drive mechanism of the reservoir where it start with fluid expansion with Fluid expansion Pore volume compressibility and water influx with the percentage shown in the figure was the dominated driving mechanism . and at 1985 the water injection was started . B-Bottom drive aquifer

179 Figure 132 Bottom drive aquifer

CHAPTER 4

C-Graphical method graph

Figure 133 graphical method

The Graphical method shows the relationship between (F/Et ) and (We/ Et ) where the intercept is the original oil in place (OOIP ) as shown in the figure = 205.79 MMSTB D-Analytical method graph :

Figure 134 Analytical method

180

CHAPTER 4

Prediction results: 1-average gas and oil rate with time

Figure 135 Gas and oil rate

2-Average water injected with cumulative oil produced

Figure 136 Average water injected with cumulative oil produced

181

CHAPTER 4

3-cumulative gas and oil produced with time

Figure 137 cumulative gas and oil produced

4 - Cumulative oil produced with water injected

Figure 138 Cumulative oil produced with water injected

182

CHAPTER 4

5-water injection And cumulative oil production with time

Figure 139 water injection And cumulative oil production with time

6-oil saturation with time

Figure 140 oil saturation with time

183

CHAPTER 4

7- Oil recovery factor

Figure 141 recovery factor

Recovery factor is 47 % at 1-1-2035

184

CHAPTER 4

4.6 ECLIPSE Results 1- Model Eclipse model the reservoir with its wells in present time and in future till reservoir depletion with different properties.

Figure 142 Reservoir Model

Side view of reservoir with different saturations.

Figure 143 Side view 185

CHAPTER 4

2- GRAPHES a. Total production (Oil, Gas & Water) , total water injection verses Years

Total oil production (FOPT) Total gas production (FGPT) Total water Production (FWPT) Total water injection (FWIT)

Figure 144 FOPT,FGPT, FWPT, FWIT Vs Date

b. Production and injection rates verses date Field Gas Production Rate (FGPR) Field Oil Production Rate (FOPR) Field Water Production Rate (FWPR) Field Water Injection Rate (FWIR)

Figure 145FGPR, FOPR, FWPR, FWIR Vs Date 186

CHAPTER 4

3- Originally In Place Calculations

Figure 146 In place calculation

Eclipse provide report for each year till depletion in the previous report show that:Original Oil In Place 204.653154 MMSTB Original Water In Place 215.737127 MMSTB Original Gas In Place 43664.797 MMSCF

Prediction

187

CHAPTER 4

Recommendation Final Recovery factor can be increase by increasing number of produced wells or increase the injection rate . New produced well in marine zone at cell (9,2) Result recovery factor = .68

Cell(9,2) New produced well

Figure 147 New Well

Increasing number of produced wells in highly oil saturation cells and thick formation will be economically and increasing the recovery factor and have the optimum production

.68 RF 0.63 Series2 Series1 4 no. of wells 3

0

1

2

3

4

Figure 148 Comparison no. of wells

188

5

CHAPTER 4

RF With and Without Injection The following chart shows the importsance of the water injection in the reservoir to increase the recovery factor. So By increasing the injection wells the production increase 70 60

RF %

50 40 Wiyhout inj. 30

With inj.

20 10 0 1

Figure 149 Comparison Inj. Wells

189

CHAPTER 4

Conclusion Based on the case study and the previous explanation, the following can be concluded: MBE by Excel calculations must be used to know the reservoir type and primary reserve estimate. Monte Carlo simulation (probabilistic approach) proved to be more successful in estimating IOIP as it gives all the possible values based on the data available (P10, P50, P90). MBAL Material Balance Tool can be used to confirm the IOIP from Monte Carlo and can also be used to determine the reservoir driving mechanism. ECLIPSE Simulation very useful for model the reservoir , shows the whole parameters of the reservoir with time changing , predict the reservoir behavior with changing conditions .

The summary of IOIP and RF results of the case study can be summarized as follows. Table 50 Conclusion

OOIP RF%

MBE Calculation 205.6 @ 2035 .69

Montecalo 209 Not applicaple

190

MBE MBAL 205.3 .47

ECLIPSE 204 .65

REFERENCES

REFERENCES 1- The Petroleum Society of CIM, Determination of Oil and Gas Reserves, Canada,1994. 2- Repsol YPF, Reserves Reporting System, Louisiana, 2005. 3- Arps,J.J, 1945, Analysis of Decline Curves, Trans. AIME 4- Arps,J.J, 1956, Estimation of primary oil reserves, Trans. AIME 5- Ahmed, Tarek. Reservoir Engineering Handbook. Amsterdam , Elsevier, GPP, 2006.Print. 6- Reservoir Issue 1, part of Reservoir Engineering for Geologists, Fekete, February 2008 7- Schilthius,R., Solution-Gas-Drive Reservoirs, Trans. AIME, 1936, Vol.118. 8- Clark, N., Elements of Petroleum Reservoirs. Dallas, TX:SPE, 1969. 9- Cole, F., Reservoir Engineering Manual, Houston, TX: Gulf Publishing Co., 1969. 10- Havlena, D., and Odeh, A. S., “The Material Balance as an Equation of a Straight. Line,” JPT, August 1963, 11- Havlena, D., and Odeh, A. S., “The Material Balance as an Equation of a Straight Line, Part II—Field Cases,” JPT, July 1963. 12-

Dake, L., The Practice of Reservoir Engineering, Amsterdam: Elsevier. 1994.

13- Dake, L. P., Fundamentals of Reservoir Engineering. Amsterdam: Elsevier. 1978. 14- Van Everdingen, A., and Hurst, W., “The Application of the Laplace Transformation to Flow Problems in Reservoirs,” Trans. AIME, 1949. 15- B.C.Craft, Applied Petroleum Reservoir Engineering,2nd edition ,1991. 16- James J. Sheng,Ph.D.,Modern Chemical Enhanced Oil Recovery Theory and Practices, Elsevier, GPP,2010, Print 17- Sara Thomas , Chemical EOR-The Past, Does It Have A Future , SPE Distinguished Lecturer Series ,2005. 18- George S. Monte Carlo: Concepts, Algorithms, and Applications. New York, Springer, 2008. Print 19- Metropolis, N. and Ulam, S., “The Monte Carlo Method” J. Amer. Stat. Assoc., 1949. 20- “Petroleum Reserves Definitions” published by SPE, 1964. 191

REFERENCES

21- Schlumberger ,Simulation Software Manuals , Eclipse , 2005. 22- Petroleum Expert, MBAL Explanation, www.petex.com/products/?ssi=4 23- Islam Amged Nassar , Reservoir Project , BUE, 2010 24- Petroleum Experts, Reservoir Analytical Simulation , MBAL, version 7 , 2003.

192

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