Waterflooding

Waterflooding and Simulation

Contents Abstract............................................................................................................... 3 1.0

Introduction............................................................................................... 4

2.0

Part A.......................................................................................................... 5

2.1

Reservoir simulation..................................................................................5

2.2

Principle of waterflooding..........................................................................6

2.3

Waterflood candidates..............................................................................7

2.4

Optimum waterflooding............................................................................ 9

2.5

Selection of waterflood pattern...............................................................10

2.5.1

Irregular injection patterns...............................................................10

2.5.2

Peripheral injection patterns.............................................................10

2.5.3

Regular injection patterns.................................................................11

2.5.4

Crestal and basal injection patterns..................................................12

2.6

Estimation of the overall waterflood recovery efficiency........................13

2.6.1

The oil in place at the start of the project.........................................13

2.6.2

Displacement sweep efficiency, ED...................................................13

2.6.3

Areal sweep efficiency, EA.................................................................14

2.6.4

Vertical sweep efficiency, EV.............................................................15

2.7

Case study (Robertson Field)...................................................................16

2.8

Discussion............................................................................................... 17

3.0

Part B:....................................................................................................... 18

3.1

Simulation............................................................................................... 18

3.1.1

Initial case......................................................................................... 19

3.1.2

First Strategy (Inverted nine-spot pattern).......................................20

3.1.3

Second strategy (Five-spot pattern)..................................................21

3.2

Result...................................................................................................... 22

3.3

Discussion............................................................................................... 24

4.0

Conclusion................................................................................................ 25

5.0

Reference................................................................................................. 26

2

Abstract The main aim of this report is to conduct a research in waterflooding process and to implement the fundamentals of waterflooding process in reservoir simulation. Waterflooding is perhaps the most common technique used so far as a secondary recovery mechanism because of the availability of the water, the low cost of water compared with other fluids and the water can be injected into the reservoir formation easily. The principle of waterflooding is briefly defined as the injection of water into the reservoir formation to displace the oil and therefore maximize the oil production and increase the recovery factor. In Part A, a brief introduction of reservoir simulation is present with the steps involved in simulation. The principle of waterflooding and the factors which make the reservoir a successful candidate for waterflooding project will be discussed in Part A. The critical point for a successful waterflooding project is determining the optimum time to start. Thus, there are several aspects must be considered to decide the optimum time. These aspects are also discussed briefly in the part. Furthermore, the method of estimating the waterflooding recovery factor is described in detail with the expressions used. At the end of this part, a case study of Robertson filed is considered to examine and discuss the success of waterflooding in the field. In Part B, a simulation is performed by using Petrel E&P to model a reservoir and apply different development strategies in order to predict and analyze the performance of the reservoir under waterflooding process. Two strategies have been established based on the well arrangement used in the case study in Part A. In the first strategy, an inverted nine-spot pattern is used, whereas a five-spot pattern is used for the second strategy. Both strategies result a successful waterflooding, however, the second strategy is more efficient because of the higher oil production and thus more profitability.

3

1.0

Introduction

Reserve of an oil field is defined as the quantities of the hydrocarbons in a reservoir which are commercially recoverable from known accumulations and a given date by various techniques. The extractable amount of hydrocarbon is dominated by a recovery factor which depends on many variables such as the reservoir properties, fluids properties, reservoir drive mechanisms, etc. The reservoir drive mechanism refers to the natural energy of the reservoir that moves the oil to the wellbore without using any additional supplements. The natural drive mechanisms like the gas cap drive and water drive are known as the primary oil recovery. In most cases, only 5 to 30 % of the original oil in place (OOIP) can be recovered by the primary oil recovery. The insufficient recovered oil in this mechanism led to different practices to support the neutral energy of the reservoir by injecting immiscible gas or water into the reservoir formation which is known as the secondary oil recovery. Up to 30 % additional recovery of the OOIP can be recovered by using the secondary oil recovery technique. In some certain reservoirs, a tertiary oil recovery (enhanced oil recovery, EOR) is required to recover the residual oil left behind in the reservoir after inefficient primary and secondary recovery methods. The use of the EOR methods is usually limited due to economic considerations. The oil recovery classifications are shown in Fig. 1. In this report, the waterflooding process as a secondary oil recovery is highlighted. The cost of waterflooding process is relatively low in comparison with other oil recovery methods. The process often involves converting some production wells into injection wells to increase the contacted zone between the oil and injected water. Furthermore, reservoir simulation may also be involved in waterflooding process to predict the fluid behaviour in the reservoir and, therefore, optimizing the process and maximizing the recovered oil from waterflooding project. More detail of the process is discussed in the subsequent section and linked with simulation studies to better understanding.

4

Figure 1: The categories of the oil recovery mechanisms (SBC, 2015).

2.0 2.1

Part A Reservoir simulation

Basically, the term simulation means the representation of dynamic processes by either a physical or theoretical model. In petroleum engineering, modelling the fluid flow in porous media is significant and therefore reservoir simulation must be preformed. Reservoir simulation refers to the use of means that provides a numerical model of the petrophysical and geological characteristics of a reservoir in order to predict and analyze the reservoir fluid performance under different conditions. The reservoir simulation modeling usually consists of three parts in its basic form: 1. A geological model: it is a mathematical description of the reservoir and its petrophysical and geological characteristics to form a volumetric grid which describes the porous rock formation. 2. A flow model: it is a mathematical model which describes the fluid flow in a porous media. This is typically given as a set of equations of the conservation of mass and volume together. 3. A well model: it describes the flow in and out of the reservoir fluids and computes the production and injection rates for a given bottom hole pressure, or the opposite. The major purpose of reservoir simulation is to predict the reservoir fluids behaviour over time and optimize the development plans to maximize the oil recovery. This obviously will assist in taking the investment and operational decisions. Although the reservoir simulation is an invaluable tool, the need of simulation studies depends greatly on some factors such as the geological setting, the field maturity, and the production environment (offshore or onshore).

5

There are several reservoir simulators designed to model the flow in reservoir system. These simulators are computer programs that solve fluid flow problems using mathematical techniques based on three fundamental equations 1) Darcy’s law, 2) material balance equation, and 3) conservation of mass equations. A typical simulator flow chart is shown in Fig.2.

2.2

Figure 2: A typical simulator flow chart (Fanchi and John, 2005). Principle of waterflooding

The injection of water into the reservoir to displace the oil and therefore increase the production is called waterflooding, as illustrated in Fig. 3. This process is perhaps one of the most common methods used as secondary oil recovery. Historically, waterflooding was recognized accidentally in more than 100 years ago when shallow water entered an oil well, and consequently the oil production from that well was diminished, whereas the production from the surrounding wells was increased. The widespread waterflooding began in the early 1950’s and grew steadily until now to become the dominant fluid injection technique. In fact, the principle of waterflooding is the same as the pressure maintenance principle. In both cases, the oil is displaced by the injected water but the only difference is that the waterflooding results a significant increase in the oil production while the pressure maintenance might not. In the typical pressure maintenance process, the water is injected into the aquifer to either maintain or increase the reservoir pressure at or near the bubble point pressure or to augment the water drive by retarding the natural decline in the existing reservoir pressure.

6

Figure 3: Illustration of waterflooding process. There are different reasons in which the waterflooding has become the most widely and successfully method ever used in the world as an oil recovery mechanism. These primary reasons are: 1. The ease availability of the water particularly in offshore fields. 2. The low cost of water compared with other fluids. 3. The water can be injected into the reservoir formation easily. 4. The efficient and effective displacement of the oil by the water. 2.3 Waterflood candidates Various factors make an oil reservoir a successful candidate for waterflooding. Thomas, Mahoney, and Winter (1989) generalize these factors by considering the following reservoir characteristics: 

Reservoir geometry

The geometry of the reservoir plays an important role in the behaviour of the waterflooding. The reservoir’s geometry will directly impact on the location of the wells and also the number of platforms in case of an offshore filed, and, therefore, will essentially govern the oil recovery by the water injection practices. The previous performance of the reservoir and good analysis of the reservoir’s geometry are necessary not only to define the strength of natural water drive, but also to know the need of an additional supplement of the natural energy by injection. The water injection is considered unnecessary if the natural water derive classified as an active mechanism.

7



Fluid properties

The physical fluid characteristics of a given reservoir have an important effect on whether the reservoir is required a further development or not by the water injection. The oil viscosity is considered as the principal fluid characteristic which affects on the percentage of success of the waterflooding process. The most important variable to be considered is actually the mobility ratio, M, that defines as the mobility of the displacing fluid to the mobility of the displaced fluid i.e. the effective permeability to the viscosity of the displacing and displaced fluids, the mobility ratio M can be expressed as follows;

So, for waterflooding;

The above expression of the mobility ratio has been standardized by the Society of Petroleum Engineering (SPE) since 1957 (James and William, 1999). A good waterflooding has a favourable mobility ratio equals to or is less than 1. This means the oil will flow better than the water and the water will displace the oil easily. Conversely, if the mobility ratio is greater than 1 (unfavourable mobility ratio), then the water will flow better than the oil and the displacement effectiveness of oil by water will decrease. In this case (extremely viscous oil), the water will leave behind much of the by-passed oil. Generally, a range from 0.02 to 2.0 of the mobility ratio was encountered during the waterflooding (Forrest, 1975). 

Reservoir depth

The depth of the reservoir is an important factor on either a secondary or tertiary oil recovery process and it may affect both the economic and technical sides of the project. In the economic aspect, the operating costs and investment increases as the reservoir depth increases. This generally results an increase in the drilling and lifting operation costs. In the technical aspect, the reservoir depth should be deep enough so that the injection pressure would be less than the fracture pressure of the reservoir. Otherwise, a poor waterflooding process would be occurred as a consequence of the high water injection rates. In a typical waterflood process, a critical pressure of approximately 1 psi/ft of depth must not be exceeded so no fractures will be induced in the reservoir. As a result,

8

a gradient pressure of 0.75 psi/ft of depth would be normally sufficient to provide efficient waterflood (Ahmed, 2006). 

Fluid saturations and rock properties

The petrophysical rock properties such as porosity, average permeability and fluid saturations, have a direct influence on the success of the waterflooding process. Insufficient oil saturation and porosity in a reservoir will result a noneffective waterflooding process and, thus, would not be economically justified because of the produced oil will not be enough to offset the operating costs and investment. The average permeability of the reservoir must be high enough to allow sufficient water injection without fracturing the reservoir. 

Reservoir uniformity and pay continuity

The reservoir uniformity considers as a main physical criterion for successful waterflooding. The existence of faults, reservoir structure and permeability trends affect the location of new injection wells where a good communication must be introduced between the production and injection wells. In some reservoirs which are significantly heterogeneous, a serious channelling exists, and therefore a lot of reservoir oil will by-passed and the waterflooding might be considered useless and unprofitable. Also, the pay continuity plays an important role for a successful waterflooding. 

Primary reservoir driving mechanism

The primary oil recovery mechanism should be considered carefully for any potential waterflooding process. Gas cap and water derive reservoirs are not normally considered to be appropriate candidates for waterflooding. However, water injection may be introduced for both cases in order to maintain the pressure. A reservoir dominated by solution gas drive mechanism is usually considered the best candidate for successful waterflooding due to low primary recovery exists in the reservoir.

2.4

Optimum waterflooding

The critical point for a successful waterflooding project is determining the optimum time to start. The optimum time is actually determining on the basis of the reservoir pressure. Ahmed (2006) summarized the most important procedure which has to be considered and calculated to determine the optimum time for waterflooding, as follows;

9

      

Prospect oil recovery. Production rates of fluids. Financial investment of the project. The quality and availability of the required water to be injected. Costs involved in drilling new wells for injection or converting existing wells from producer to injector. Costs involved in pumping equipment and water treatment. Costs involved in operation and maintenance of the water facilities.

These points should be examined and calculated for many times to determine the net income for each case when the waterflooding is required. The best case which meets the desirable objectives and maximizes the profit is selected. Additionally, Cole (1969) suggested technical and economic factors which also must be considered to determine the optimum time (or pressure) to start waterflooding. These factors are listed below; 

Reservoir oil viscosity

As mentioned earlier, the oil viscosity is the principle fluid characteristic that affects on the degree of success of waterflooding project. The water injection process is usually initiated when the reservoir pressure closes to its bubble point pressure where the oil viscosity becomes at its minimum value at this pressure. Therefore, the oil mobility increases as the oil viscosity decreases, resulting mobility ratio around 1 and better sweeping efficiency. 

Free gas saturation and productivity of producing wells

In case of water injection, it is preferred that the reservoir has initial gas saturation up to 10 % and this occurs only at a pressure which is below the bubble point pressure. Conversely, a higher pressure is desirable to increase the productivity of producing wells and which, therefore, extends the flowing time of the wells, shortens the project’s overall life, and decreases the operating costs. 

Cost of injection equipment

The cost is related directly to the reservoir pressure where at higher pressure the cost increases. On the other hand, the cost of injection equipment is relatively less at low reservoir pressure. 

Overall life of the reservoir and the effect of delaying investment

As the operating expenses are a very important part of the total costs, the water injection should start as early as possible. On the other hand, a delayed investment in the facilities of water injection may be desirable because of the effect of time on the value of money. 2.5

Selection of waterflood pattern

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The selection of waterflood pattern is one of the most important steps when designing a waterflooding project. The major goal is to choose the appropriate pattern which provides a maximum contact of the injection fluid with the target oil. The choice must be consistent and related with the existing well pattern, the reservoir geometry and geology, and the objective of waterflooding. The economics of the waterflooding project can dictate the selection of the flooding pattern by either converting existing producer wells into injectors or drilling infill injection wells. This will lead to eliminate some patterns from consideration automatically. In general, a proper waterflood pattern for a reservoir should meet the following criteria: 1. Provide the desired oil production rate. 2. Provide necessary water injection rate to yield the desired oil production rate. 3. Maximize oil recovery. 4. Take advantage of reservoir characteristics such as faults, fractures, permeability trends, etc. 5. Adjust with existing well pattern and require less infill wells. Basically, there are four common types of the well arrangements being used as waterflood patterns: 2.5.1 Irregular injection patterns Some fields were developed using irregular patterns due to the use of slant hole drilling technique and/or the surface or subsurface topology. This results nonuniform location of the production or injection wells. Other factors such as the faults, variation in porosity and permeability trends may yield irregular patterns. 2.5.2 Peripheral injection patterns The peripheral flooding patterns utilise all or a part of reservoir external boundary as locations of the injection wells, see Fig. 4. It usually refers as a line flood, if a single line of wells located either along one side or down the middle of the field. This type of flooding patterns has several advantages such as 1) it yields a maximum oil recovery with fewer injection wells, and, thus, less initial investment, 2) it results less water production and delays the water breakthrough, and 3) it can be used with dipping reservoir and reservoir with permeability variations. The main disadvantage of peripheral flooding patterns happens when the reservoir has high gas saturation since it will take a long time until the reservoir gas space is filled up with the injected water. Consequently, a delay in a significant oil recovery response will occur and a considerable water injection expense is required.

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Figure 4: Illustration of two common cases in which peripheral 2.5.3 Regular injection patterns flooding patterns are used. Many fields were developed by using a regular injection pattern due to the fact that most of the oil leases divided into squares with different ownership. The most common regular patterns of the production and injection well arrangements, as shown in Fig. 5, are:

Figure 5: The geometry of the most common regular injection patterns. 

Direct line drive

In this flooding pattern, the lines of production and injection wells are directly offset each other. Two important variables is characterized this pattern: 1) d = which is the distance between adjacent lines of the producers and injectors, and 2) a = which is the distance between adjacent wells in the same line. In the direct line drive pattern, the ratio of producers to injectors is unity.

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

Staggered line drive

This pattern is actually a modified direct line drive pattern, where the wells are in lines but not directly oppased to each other any more. Accordingly, the lines of porduction and injection wells in staggered line drive are moved in which the wells in alternate lines are dispalced by a distance of a/2. 

Five-spot

The five-spot pattern is a special case of the staggered line drive pattern in which the d/a ratio is constant, and equals 0.5. This pattern is the most commonly flooding pattern used in most areas since its conductivity is high where the shortest flow path is a straight line between the producer and injector. In the five-spot pattern, any four injector wells form a square with a producer well and thus the ratio of producers to injectors is unity. 

Seven-spot

This pattern has two injector wells per a producer well and its merit that the injectivity is low. This pattern can be considered as a staggered line drive but with a d/a ratio of 0.866. The inverted seven-spot pattern has only one injector well per a pattern and is occasionally used. The inverted seven-spot also refers as four-spot pattern where both are identical. 

Nine-spot

This pattern can be developed from a five-spot pattern but with extra injector wells to be drilled at the middle of each side of the square. This pattern can be very useful if a high injection rate is required due to the low permeability. The major advantage of nine-spot pattern is its flexibility. The inverted nine-spot pattern is usually utilised more than the normal nine-spot pattern, especially when the fluid injectivity is high. 2.5.4 Crestal and basal injection patterns In the crestal pattern, the injector wells are located at the top of the structure and it is most likely used with gas injections project. In the basal pattern, the injector wells are located at the bottom of the structure and it is usually used with water injection projects with extra benefits can be gained from gravity segregation. Fig. 6 shows an example of both patterns.

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Figure 6: Crestal and basal injection patterns used with dipping reservoirs. 2.6 recovery efficiency

Estimation

of

the

overall

waterflood

The overall recovery efficiency (factor) due to waterflooding project or any fluid displacement process can be determined at any time of the project from the following expression;

The generalized expression used to predict the cumulative oil produced (oil displaced by water injection) in waterflooding project is given by the following equations:

Therefore, the oil recovery factor can be estimated only if the following factors are known: 2.6.1 The oil in place at the start of the project Reliable predications of the waterflooding performance or accurate interpretations of historical waterflooding behaviour can only be known if a good estimation of the reservoir oil in place at the start of waterflooding project is available. The oil in place at the start of waterflooding is given by:

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2.6.2 Displacement sweep efficiency, ED It is defined as the fraction of oil in place that will be displaced by water and has been recovered from the swept zone at any particular time. The displacement sweep efficiency will usually increase at different stages of the waterflooding process and can be expressed as follows;

2.6.3 Areal sweep efficiency, EA The areal sweep efficiency represents the fraction of the reservoir area (or the total flood pattern) which has been contacted by the injected water at a given time during a flood. The areal sweep efficiency increases gradually with the start of water injection until the breakthrough happens, which after it continues to increase slowly. It depends primarily on the following factors: 1. 2. 3. 4. 5.

The relative flow properties of water and oil (mobility ratio). The location of production and injection wells (waterflood pattern). Pressure distribution between the production and injection wells. Directional permeability. Total volume injected.

The progression of waterflooding process according to areal sweep view is illustrated in Fig. 7. At Time 1, the injection is initiated and a water bank is formed. At this time the flow is characterized by a radial flow system and the reservoir normally doesn’t respond to the waterflooding. Only a rapid reservoir response will occur if no gas exists at the start of waterflooding. The displacing water and displaced oil are moved to fill up the gas space and a complete fill-up

15

is occurred at the end of Time 2. During this time, the flow system is not strictly radial and is relatively complex. Approximately, at the mid-life of the waterflooding (Time 3), the oil production rate will be essentially the same as the water injection rate. This is due to the fact that no free gas remaining in the flood pattern. The edge of water bank will eventually reach the producer well and the time of breakthrough is approached. At Time 4, a rapid rise in the water production is occurred with a significant decrease in oil flow rate.

2.6.4 Vertical V Figuresweep 7: The efficiency, progression Eof waterflooding process with five-spot pattern. The vertical sweep efficiency is defined as the fraction of a pay zone in vertical plane that is contacted by water. The vertical sweep efficiency sometimes refers to the invasion sweep efficiency and it depends basically on the mobility ratio, the degree of the permeability stratification existed in the reservoir, and the cumulative water injected. As a result of the non-uniform permeability, the injected water will tend to move irregularly through the reservoir and, therefore, it is often unable to contact the entire vertical section of the reservoir. The permeability variation of the reservoir is perhaps one of the greatest uncertainties which can be encountered in designing a waterflooding project. Consequently, the permeability variation is considered as the most significant factor affecting the vertical sweep efficiency. Moreover, the mobility ratio is also important to estimate the vertical sweep efficiency; a decrease in the mobility ratio will improve the vertical sweep efficiency. An estimate of the vertical sweep efficiency can be calculated by two traditional methods; 1) Stiles method and 2) Dykstra Parsons method. Both methods are assumed that the reservoir is consisted of an idealized layered system which is based on the permeability ordering. Other assumptions are also considered in the two methods such as no cross-flow between the layers, linear flow, immiscible displacement and piston-like displacement. These methods can be

16

found in waterflood textbooks and they are too lengthy to be presented in detail here (see references 2 and 4). The progression of waterflooding process with vertical cross-section of a reservoir is illustrated in Fig. 8. In this example, the reservoir is composed of 8 layers with different permeabilities. At early time of waterflooding process, the injected water displaces the oil in high permeable layers increasingly. On the other hand, some residual oil has been left behind in the reservoir layers with low permeability. Finally, a high water-oil ratio (WOR) is noticed after the water breakthrough time.

Figure 8: The progression of waterflooding process in vertical plane of a reservoir with 2.7 Case study (Robertson Field) permeability variation. In the purpose of better understating of waterflooding process, a case study of waterflood field has been examined. The selected field is Robertson Clearfork Unit (RCU). The field is located geologically in Gaines County, west Texas on the north-eastern part of the Central Basin Platform. The production began in the early 1950’s with an initial well development of 40 acre. The waterflooding began in 1971 with six injectors and progressed throughout the unit. In spite of the economically success, the results were less than predicted (Barbe and Schnoebeien, 1987). The reservoir is a shallow shelf carbonate (Permian Leonard age) and typically heterogeneous, both vertically and laterally. The physical properties of the reservoir are shown in Table 1. The primary oil recovery was dependent entirely on the solution gas derive. The recovery factor from this mechanism was

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estimated 8 % of the OOIP. This relatively low primary recovery was the major reason to initiate waterflooding process for the field. Table 1: The physical properties of the Robertson field reservoir (George and Stiles, 1978). Reservoi r properti es

Area (acres) x depth (ft)

Porosit y (%)

Permeabili ty (md)

Saturation pressure (psi)

Oil viscosity (cp)

value

4,800 x 5500

6.3

0,65

1640

1.2

Waterflooding strategy of Robertson filed The well arrangement of the field was initially developed with 40 acres per producer well. Since the waterflooding began, some wells were converted into injectors, thus creating five-spot waterflood pattern. The first stage of infill wells was by drilling one additional well on each 40 acre, therefore developing the fivespot pattern to the inverted nine-spot pattern i.e. one injection well per three production wells. This pattern is still in operation up to date as shown in Fig. 9. The oil recovery factor of waterflooding was estimated to be 18 % of the OOIP. The data used to estimate the waterflood recovery factor is shown in Table 2. Table 2: The reservoir parameters for Robertson field at the start of waterflooding process (Barbe and Schnoebeien, 1987). parame ter

Gross thickness (ft)

Mobili ty ratio

Gas saturati on

Water viscosity (cp)

Initial oil saturat ion

Residual oil saturation

value

1400

0.96

0,65

0.6

0.708

0.34

2.8

Discussion Figure 9: The evolution of waterflooding patterns in Robertson field.

Since the gas solution drive was the primary recovery mechanism in Robertson filed and only 8 % of OOIP was recovered, the field was highly candidate for waterflooding process. Although some difficulties had been encountered, the waterflooding showed a successful recovery and increased the overall recovery efficiency to 18 %. The difficulty can be summarized in the reservoir characteristics. In such carbonate reservoir, a high degree of vertical and areal 18

heterogeneity is present with relatively low permeability and porosity. Furthermore, the degree of the permeability stratification existing in the reservoir is significant and, thus, resulting poor sweep efficiency and poor lateral and vertical continuity of the reservoir flow. The inadequate completions and the reservoir discontinuities limit the floodable volume of the total reservoir and therefore influence on the waterflooding performance. Typically the waterflooding began with five-spot pattern which is the most commonly used in such condition. To overcome the reservoir poor continuity and high injectivity, the waterflood five-spot pattern was modified to inverted ninespot pattern by drilling an extra producer at the middle of each side. This obviously increased the well density (the number of wells in a specified area). Consequently, the well spacing is decreased and provided more access to the unswept parts of the reservoir. This waterflood pattern was not adequate to balance the injectivity with withdraws, so some production wells were converted to injection wells. In terms of pressure, the differential pressure between the production well and injection well has decreased due to reducing the distance between wells. The mobility ratio during the waterflooding process equals 0.96 which is around the favourable range (less than 1). This indicates that the water flow was better than oil and, thus, it displaced oil easily and effectively.

3.0 3.1

Part B: Simulation

In this part of the report, a simulation of reservoir has been performed by using Petrel simulator reservoir engineering. Petrel is computer software owned by

19

Schlumberger which provides integrated solutions from exploration to production. The main goal of using Petrel was to propose two development strategies using waterflooding. In addition of the two proposed cases, an initial case has been constructed in Petrel based on a given strategy. The given strategy includes two production wells (P01 and P02) and two injection wells (I01 and I02). A simple gird has been made by using three surfaces (top, middle and base surfaces) with 100 meters of ∆X and ∆Y. So, two zones have already been created and each zone has 5 layers. The petrophysical reservoir properties (porosity, permeability and net to gross) were populated by using petrophysical modelling which has produced a random distribution of the properties through the model according to a certain seed number. Table 3 shows the given reservoir properties that have been inputted into Petrel to make a three dimensions reservoir model. The seed number used is 16158970; therefore a unique reservoir model has been created associating with that seed number. Table 3: The reservoir properties used for petrophysical modelling in Petrel. Property Porosity (fraction) Permeabil ity (mD) Net to Gross (fraction)

Minimum

Maximum

Mean

Standard deviation

Distributi on

0.03

0.45

0.29

0.058

Normal

70

800

300

150

Log Normal

0.05

0.65

0.5

0.134

Normal

Other reservoir properties are listed below:          

Gas oil contact = 1500 m Water oil contact = 2600 m Bubble point of crude oil = 80 bars Fracture pressure = 350 bars Initial pressure = 256 bars# Reservoir depth = 3000 m Reservoir temperature = 76.85 oC Oil gravity = 30 API Oil density = 875 Kg/m3 Water salinity = 30000 ppm

The original oil in place (OOIP) was calculated 1209 x 10 6 sm3. Other parameters were also calculated for both zones as shown in Table 4.

Table 4: The calculated parameters for both zones with the total the OOIP from volume calculation in Petrel.

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Parameters/zone Bulk volume (m3) Net volume (m3) Pore volume (m3) Segments Total STOIIP (sm3)

Zone 1 6389 x 106 3104 x 106 856 x 106 Segment 1

Zone 2 2606 x 106 1210 x 106 353 x 106 Segment 1 1209 x106

3.1.1 Initial case In the initial case, the fluid model has been made by using a default model for Black oil and the consolidated sandstone for the rock physic function. After that, the model has been initialized by using the equilibration method and the wells also were completed and perforated. The simulation was run from 2015 to 2035 and the result was visualized. In this strategy, the oil production cumulative was 5.6 x 107 sm3 and the recovery factor was calculated according to the following equation; Recovery Factor, RF = cumulative oil / original oil in place 

RF (initial case) = 5.6 x 107 / 1209 x 106 = 4.6 %

It seems that the recovered oil in this strategy is relatively low and this is because the number and location of the wells used. Therefore, additional two strategies have been performed to increase the oil recovery factor and maximize the oil production in the seam period. However, the new strategies were constructed based on the case study (Robertson field) and the waterflooding research in the Part A of this report. As mentioned earlier in Part A, a successful development strategy of any field by using waterflooding project depends on many factors which must be considered carefully. The selection of the well pattern is one of the most important steps to be considered when designing waterflooding. This well arrangement will affect in someway the amount of injected water that should be in contact with the target oil in reservoir. Therefore, the reservoir properties, especially the mobility ratio and permeability, will influence directly the distribution of the injected water and the efficiency of waterflooding process. In Robertson field, waterflooding project has started since the recovered oil from the primary was only 8 % of the OOIP. Five-spot pattern, which is the most common waterflood pattern, was the first well arrangement for waterflooding in the field. The oil production increased but also the injectivity increased, so the pattern was modified to an inverted nine-spot pattern to balance the withdraws with the injectivity. In the inverted nine-spot pattern, any eight production wells form a square with an injection well and thus the ratio of producers to injectors is three. Back to the simulation, the five-spot and inverted nine-spot patterns were proposed and implemented as new two development strategies in the reservoir.

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The results were compared with the initial case and the graphs were plotted as will be discussed in the subsequent section. 3.1.2 First Strategy (Inverted nine-spot pattern) The same procedures in the initial case were conducted in Petrel but this time new injectors and producers were inserted in order to improve the oil recovery and the waterflooding efficiency. In the first strategy, the well arrangement was based on the inverted nine-spot pattern. The well location and spacing was selected according to the net gross and permeability where the new producers drilled in the most potential oil zone. The injection well pressure was set 290 bars which is less than the fracture pressure, 350 bars, to insure that it doesn’t exceed the safety margin and then no formation damage will occur. In addition, the production well pressure was set to be 95 bars which is higher than the bubble point pressure, 80 bars, in order to have only oil production without gas. In Fig. 10, the inverted nine-spot waterflood pattern is illustrated. It is clear that only one injector in the middle surrounding with 8 producers in which 9 wells in total were used. In comparison with the initial case, a massive increase in oil production rate was noticed and thus higher oil cumulative. This is due to increasing the producer wells where each three form a square with the injector.

Figure 10: The first strategy with inverted nine-spot waterflood pattern. In this strategy the oil production cumulative was calculated 9.0 x 10 7 sm3. So the oil recovery factor was estimated as follows;

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

RF (first strategy) = 9.0 x 107 / 1209 x 106 = 7.5 %

There is an increase around 3 % in the oil recovery from the initial case. However, the water production was also increased and therefore more water handling facilities should be taken in consideration. 3.1.3 Second strategy (Five-spot pattern) In the second strategy, the five-spot waterflood pattern was selected for the well arrangement. In this pattern, the ratio of producer to injector is unity. The pattern is formed by some modification in the inverted nine-spot pattern where some wells were converted from production wells to injection wells. The reservoir model with the wells location is shown in Fig. 11. As a result of using this pattern, a considerable increase in the oil production occurred where the cumulative oil production was 1.1 x 108 sm3. In comparison with the initial case and the first strategy, the second strategy is the highest oil production cumulative in the period of 20 years. Furthermore, the water production rate is too high from the beginning of the waterflooding project. The oil recovery factor was estimated as follow; 

RF (second strategy) = 1.1 x 108 / 1209 x 106 = 9.1 %

Figure 11: The second strategy with five-spot waterflood pattern In all cases, after the well location was selected, the well completion (casing) and perforations of the target interval were performed automatically by Well completion design in Petrel. An example of the well completion is shown in Fig 12.

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3.2 Result Figure 12: An example of the well completion and perforation for injector and

Figure 13: The oil production cumulative for each strategy. Fig. 13 shows the graphs of the oil production cumulative for each case in the period from 2015 to 2035. In this period of the time, the oil production cumulative of the second strategy is the highest production. This is due to the well arrangement and spacing where the ratio of producer to injector equals 1. This pattern is highly conductive where the shortest flow path is a straight line between the producer and injector. This leads to an effective displacement of the oil by the water and results good sweep efficiency. In this case, the second strategy is preferred over the other two strategies.

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Figure 14: The oil production rate for each strategy. Fig. 14 Shows that the oil production rates reached their peak for all cases at the beginning of the production where the highest rate was approximately 53,000 sm3/day in the first strategy. After that all rates have decreased and levelled off at constant rates because of the pressure decreased with the time. Even although the oil rate of the first strategy was higher than the oil rate of the second strategy in certain time, the rate of second strategy is preferred.

Figure 15: The watercut for all cases.

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Figure 16: the water production for all cases. Both graphs in Fig. 15 and Fig. 16 show the water production for all strategies in 20 years period. The watercut and water production rate reached their maximum value at 55 % and 10,100 sm 3 respectively by 2035 for the second strategy. This is too high water production rate in comparison with the initial and first strategies. This high rate can be interpreted because of the number of injector wells in the second strategy which is relatively higher than the injector wells in the other strategies. This high water rate indicates that the breakthrough time will defiantly occur in the second strategy much quicker than the other strategies. According to the water production rates, the first strategy is favourable over the second strategy. Although the water rate of the initial strategy is relatively less than the one of first strategy, the huge difference in the oil production of the first strategy make it the best case. The watercut of the initial and first strategies will reach 12.5 % and 25 % in 2035 respectively. However, the high water production won’t be a problem as soon as the water handling production facilities is available. 3.3

Discussion

In this section of the report, a sensitivity analysis for all strategies is considered in the basis of the number of wells and the difference between the production and cost. The number of the wells and the oil production cumulative for all strategies are shown in Table 5. First, according to the number of the well, it is clear that the initial strategy has fewer wells than the other strategies. Therefore, the total cost of the wells will be absolutely less. The cost of drilling well depends on many factors such as the reservoir geology, the production environment, the depth etc. The average cost of drilling well according to JAS data (API, 2004) is $3.4 million for an average depth of 3400 m. This cost includes the drilling operations, completion and any other involved operating costs. So, the total cost of the wells of the initial strategy will be 4 x 3.4 = $13.6 million and it will be $30.6 and $34 million for 26

the first and second strategies respectively. Although the number of wells is reasonable for all strategies, the initial strategy is preferred based on the total cost of the drilled wells. Second, the total price of oil production cumulative for 20 years is the second factor in which the best strategy will be selected. The oil price is changeable with the time according several factors such as the politics, the supply and demand tread, oil type etc., but in this estimation a constant price is considered. The oil price today is $62 per barrel, so the total oil production for the second strategy will make 62 x 691879162 = $4.3 x 10 10, whereas the oil production cumulative of the first and the initial strategies will make $3.5 x 10 10 and $2.2 x 1010 respectively. Therefore, the profit from each strategy will be the oil production cumulative price - the total cost of the wells. For example, the profit for the second strategy equals 4.3 x 1010 – 34 x106 = $4.296 x 1010. This is actually a rough estimation because many other costs are involved such as the cost of the injected water, water equipment, operating cost etc. However, it seems that all strategies are economic and thus all of them can be considered as a development project. As soon as the second strategy is the highest oil production and the most profitable, it has been selected to the waterflooding strategy for the field.

4.0 



Conclusion Reservoir simulation refers to the use of means that provides a numerical model of the petrophysical and geological characteristics of a reservoir in order to predict and analyze the reservoir fluid performance under different conditions. Although the reservoir simulation is an invaluable tool, the need of simulation studies depends greatly on some factors such as the geological

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







 



setting, the field maturity, and the production environment (offshore or onshore). In most cases, only 5 to 30 % of the original oil in place (OOIP) can be recovered by the primary oil recovery. The insufficient recovered oil in this mechanism led to different practices to support the neutral energy of the reservoir by injecting immiscible gas or water into the reservoir formation which is known as the secondary oil recovery. Up to 30 % additional recovery of the OOIP can be recovered by using the secondary oil recovery technique. Waterflooding is perhaps one of the most common methods used as secondary oil recovery, because of the availability of the water, the low cost of water compared with other fluids and the water can be injected into the reservoir formation easily. Various factors make an oil reservoir a successful candidate for waterflooding such as the reservoir geometry and depth, the mobility ratio between oil and water and rock properties. The selection of waterflood pattern is one of the most important steps when designing a waterflooding project where appropriate pattern provides a maximum contact of the injection fluid with the target oil in the reservoir. Estimation of the overall waterflood recovery factor depends on the displacement efficiency, the areal efficiency, and the vertical efficiency. Although the inadequate completions and the reservoir discontinuities in Robertson filed, waterflooding showed a successful recovery and increased the overall recovery efficiency. In simulation, Table 5 summarizes all the considered strategies and the results obtain.

Table 5: The differences between all strategies and the results obtain. Parameter/strategy Number of wells (Producers + injectors) Waterflood pattern Oil production cumulative for 20 years (sm3) Watercut (%) Recovery factor (%)

Initial strategy

First strategy

Second strategy

4

9

10

Irregular pattern

Inverted nine-spot

Five-spot

5.6 x 107

9.0 x 107

1.1 x 108

12.5

25

55

4.6

7.5

9.1

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5.0

Reference

1. SBC, (2015). Seizing the EOR Opportunity, [Online] Available from: https://www.sbc.slb.com/Our_Ideas/Energy_Perspectives/2nd %20Semester13_Content/2nd%20Semester%202013_Seizing.aspx. [Accessed 01 May 2015]. 2. James T. Smith and William M. Cobb, (1999). Waterflooding, USA. 3. Forrest F Craig Jr., (1975). The Reservoir Engineering Aspects of Waterflooding (Spe Monograph Series, Volume 3). Edition. Society of Petroleum. 4. Ahmed, PhD, PE, Tarek, (2006). Reservoir Engineering Handbook. Gulf Professional Publishing, [Online] Available from: http://0www.myilibrary.com.lispac.lsbu.ac.uk?ID=275558 [Accessed 01 May 2015]. 5. Cole, F., (1969). Reservoir Engineering Manual. Houston, TX: Gulf Publishing Company. 6. Thomas, C. E., Mahoney, C. F., and Winter, G. W., (1989). Petroleum Engineering Handbook. Dallas: Society of Petroleum Engineers. 7. Barbe, J. A., & Schnoebeien, D. J., (1987). Quantitative Analysis of Infill Performance: Robertson Clearfork Unit. Society of Petroleum Engineers, doi: 10.2118/15568-PA. 8. George, C. J., & Stiles, L. H., (1978). Improved Techniques for Evaluating Carbonate Waterfloods in West Texas. Society of Petroleum Engineers, doi: 10.2118/6739-PA. 9. Fanchi, PhD, John R., (2005). Principles of Applied Reservoir Simulation. Gulf Professional Publishing, [Online] Available from: http://www.myilibrary.com?ID=62949 [Accessed 03 May 2015]. 10.American Petroleum Institute (API), (19762004). “Joint Association Survey (JAS) on Drilling Costs.” Washington, D.C, [ONLINE] Available from: https://www1.eere.energy.gov/geothermal/pdfs/egs_chapter_6.pdf. [Accessed 08 May 2015].

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