Sonatrach's _Well Testing

INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase

Introduction to Hydrocarbon Exploitation Well Testing Section By Pratap Thimaiah

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Well Testing

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Well testing procedures are a set of tools which properly used can provide valuable clues as to the condition of production or injection wells.

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Well Testing

Well Testing

 Requirements of the following parties should be normally considered: – – – – – – – –

Senior Management Explorationists Petroleum & Reservoir Engineers Production & Facilities Engineers Drilling Engineers Oil & Gas Trading Partners Regulatory Authorities

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Well Testing  Generally oil or gas well production tests may be classified as:

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1. Periodic Production Tests 2. Deliverability Tests 3. Transient Pressure Tests

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Well Testing 1. Periodic Production Tests  

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Determination of relative quantities of oil, gas and water produced under normal producing conditions. Aid in well and reservoir operations, meeting legal & regulatory requirements.

Productivity or Deliverability Tests  

Performed on initial completions or recompletions to determine well capability under various pressure drawdown. Aid in selection of well completions & artificial lifts.

1. Transient Pressure Tests Well Testing

 

High degree of sophistication and determines formation damage or stimulation related to individual well or reservoir. Reservoir parameters such as permeability, pressure, volume and heterogeneities.

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Periodic Production Tests

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 Run routinely to physically measure oil, gas & water produced from a well under normal producing conditions.  Provide physical evidence of well conditions.  Unexpected changes such as extraneous water or gas production may signal well or reservoir problems.  Abnormal production declines may mean artificial lift problems, sand fill up, scale etc.

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Periodic Production Tests  For Oil Wells, results reported as – Oil production rates in bbl/day – Gas-Oil ratio in ft3/bbl – Water-oil ratio in % per system

Well Testing

 For Gas wells – Gas production in mscf(1000 of standard cubic feet per day) – Gas production in mmscf – Hydrocarbon liquids or water in bcpmm

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Productivity or Deliverability Tests  Physical or empirical determination of produced fluid flow versus bottom-hole pressure drawdown.  They predict what the well should produce at other pressure drawdowns.  Successfully applied to non-Darcy, below bubble point flow conditions.  Do not permit calculation of formation permeability or degree of abnormal flow restriction near wellbore.  Used as an indicator of well flow conditions.

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 They involve measurement of BH Static and flowing pressure as well as fluid rates produced to the surface

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Productivity or Deliverability Tests  Types – For Oil Wells Productivity Index Inflow Performance Flow after flow Isochronal or modified isochronal

– For Gas Wells Flow after Flow Well Testing

Isochronal or modified isochronal

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Transient Pressure Tests – Essential to analyse the current behaviour and future performance of the reservoir. – Designed to provide a quantitative analysis of the reservoir properties.

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– Conducted by creating a pressure disturbance in the reservoir and recording the pressure response at the wellbore (bottom-hole flowing pressure) – Most common tests are:  Pressure drawdown  Pressure build-up  Multi-rate  Interference  Pulse  Drill Stem  Fall off  Injectivity  Step rate

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Transient Pressure Tests  Information available from a well test includes: Effective permeability Formation damage or stimulation Flow barriers and fluid contacts Volumetric average reservoir pressure Drainage pore volume Detection, length, capacity of fractures Communication between wells

Well Testing

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Drawdown Test – Series of bottom-hole pressure measurements during a period of flow at constant producing rate. – Well is shut-in prior to the flow test for a period of time sufficient to allow the pressure to equalize throughout the formation. – Main objective  To obtain the average permeability “k” of the reservoir within the drainage area of the well.

– Sub-objectives

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 Assess the degree of damage of stimulation induced in the vicinity of the wellbore through drilling and completion practices.  To determine the pore volume and to detect reservoir heterogeneities within the drainage area of the well.

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase

Well Testing

Drawdown Test

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Drawdown Test

– During flow at constant rate of Qo, the pressure behaviour of a well in an infinite-acting reservoir (unsteady state flow) is given by:

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– Can be re-written as:

Semi-log plot of pressure drawdown data

– Then:

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Drawdown Test – Other parameters that can be obtained from plot Semi-log plot of pressure drawdown data

Well Testing

If pwf =p1hr which is found on the extension of the straight line at log t (1 hr), then:

If pressure data measured at 1 hour do not fall on that line, the line must be extrapolated to 1 hour and extrapolated value of p1 hr must be used then.

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Drawdown Test  Steps involved in drawdown test analysis: 1. Plot (pi - pwf) versus t on a log-log scale. 2. Determine the time at which the unit slope line ends.

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3. Determine the corresponding time at 1½ log cycle, ahead of the observed time in Step 2. This is the time that marks the end of the wellbore storage effect and the start of the semi-log straight line. 4. Estimate the wellbore storage coefficient from:

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Drawdown Test  Steps involved in drawdown test analysis – continued 5. Plot pwf versus t on a semi-log scale 6. Determine the start of the straight-line portion as suggested in Step 3 and draw the best line through the points.

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7. Calculate the slope of the straight line and determine the permeability k and skin factor s by applying the equations below:

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Drawdown Test 8. Plot all the recorded pressure data after teia as a function of time on a regular Cartesian scale. These data should form a straight-line relationship.

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9. Determine the slope of the pseudo steady-state line, i.e., dp/dt (commonly referred to as m’) and use the equation below to solve for the drainage area “A,” 10.Estimate the time to the end of the infinite-acting (transient flow) period, i.e., teia , which marks the beginning of the pseudo steady-state flow.

where m’ = slope of the semi-steady-state Cartesian straight-line Q = fluid flow rate, STB/day B = formation volume factor, bbl/STB

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Drawdown Test  Steps involved in drawdown test analysis – continued

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11.Calculate the shape factor CA from a expression that has been devel-oped by Earlougher (1977). Earlougher has shown that the reservoir shape factor can be estimated from the following relationship:

12.Use Table of shape factor to determine the drainage configuration of the tested well that has a value of the shape factor CA closest to that of the cal-culated one, i.e., Step 11.

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Pressure Build-up Test

– Describes the build up in wellbore pressure with time after a well has been shut in.

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– Serves to determine the static pressure – Also serves to determine: Effective reservoir permeability Extent of permeability damage around the wellbore Presence of faults and to some degree the distance to the faults Any interference between producing wells Limits of the reservoir where there is not a a strong water drive or where the aquifer is no larger than the hydrocarbon reservoir.

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Pressure Build-up Test  In pressure build-up and drawdown analyses, the following assumptions are usually made: – With regard to reservoir Homogeneous Isotropic Horizontal of uniform thickness

– With regard to fluid Single phase Slightly compressible Well Testing

Constant mo and Bo

– With regard to flow behaviour Laminar flow No gravity effects ©2005 Abalt Solutions Limited. All rights reserved

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Pressure Build-up Test

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Pressure Build-up Test

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 Horner’s Plot

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The Back-Pressure Test-Flow after Flow Conventional deliverability test: gauging the ability of the well to flow against various back pressures. Rawlins and Schellhardt (1936) –

Shut in the gas well sufficiently long for the formation pressure to equalize at the volumetric average pressure

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Place the well on production at a constant flow rate Qg1 for a sufficient time to allow the bottom-hole flowing pressure to stabilize at pwf1 to reach the pseudo steady state.

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Repeat step 2 for several rates and the stabilised bottom-hole flow pressure is recorded at each corresponding flow rate. If three or four rates are used, the test may be referred to as three-point or four-point flow test.

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

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase

Well Testing

The Back-Pressure Test

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The Back-Pressure Test  Conventional back-pressure test – Length of the flow periods is the most important factor to be considered in performing the conventional deliverability test.

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– Each rate must be maintained sufficiently long for the well to stabilise to reach the pseudosteady state. – The stabilisation time for a well in the centre of a circular or square drainage area may be estimated from:

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Isochronal Tests  Developed to shorten test times in wells that take long time to stabilize  Series of single point tests developed to estimate stabilized deliverability characteristics without actually flowing the well for time required to achieve stabilized conditions.  Conducted by alternatively producing the well, shutting in the well and allowing it to build-up average reservoir pressure before beginning of the next production period.  Pressures are measure several time increments during each flow period.

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 Ex- BHFP could be measured at 0.5,1.0,1.5 etc hrs after beginning of each flow period.  More practical for low-permeability formations.  Although not required, a final stabilized flow point usually is obtained at the end of the test. ©2005 Abalt Solutions Limited. All rights reserved

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Isochronal Tests

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Modified Isochronal Tests  Time to build up to average reservoir pressure before flowing for a certain period of time may be impractical.

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 Isochronal test is modified to shorten test times further and obtain same data without using the sometimes lengthy shut-in periods required to reach average reservoir pressure in the well’s drainage area.  The shut-in periods are of equal duration & should equal or exceed length of flow periods.  Shut-in sand face pressures are recorded immediately before each flow period and used instead of average reservoir pressures.  This test is less accurate than the isochronal test.  Note-As the duration of the shut-in periods increases, the accuracy of this test also increases.  Although not required, a final stabilized flow point usually is obtained at the end of the test.

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Modified Isochronal Tests

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Drill Stem Testing  Provides a method of temporarily completing a well and determining its productive characteristics of the specific zones  DST can provide – – – –

Good data to evaluate productivity zone Completions practises Extent of formation damage Need for stimulation

Well Testing

 Reservoir characteristics that can be estimated from analysis are: – – – – – –

Average effective permeability Reservoir pressure Wellbore damage Barriers, permeability changes & fluid contacts Radius of investigation depletion

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Drill Stem Testing  DST Operations – Running in hole on drill pipe, bottom hole assembly consisting of a packer and a surface operated valve. – The DST valve is closed while running the drill string, thus pressure inside the drill pipe is very low compared to hydrostatic mud column pressure.

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– On bottom, the packer is set to isolate desired formation zone from mud column and control valve is opened to allow formation fluids to enter the drill pipe. – After a suitable time valve is closed and pressure builds-up. – Control valve is opened again, and the flowing and shut-in periods are repeated to obtain additional data

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Drill Stem Testing Sequence of Operation:  Tool is lowered on the drill pipe to a position opposite to the formation to be tested.  Packer expands against the hole to segregate the mud filled annular section from the interval of interest.  The test valve allows formation fluids to enter the drill pipe during the test.

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 The equalizing valve allows pressure equalization after the test so the packer can be retrieved.  By opening the test valve a decline in pressure is obtained.  During the test, pressures and flow rates are measured as a function of time. ©2005 Abalt Solutions Limited. All rights reserved

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Drill Stem Testing

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Drill Stem Testing

Pressure Vs. Time Plot  Point A: As the tool is run in hole the Initial hydrostatic mud pressure is recorded.

 Point B: Initial shut in pressure, which is measured by closing the control Well Testing

valve and allowing pressure build-up towards static reservoir pressure.

 Point C: Second flowing and shutting in periods permits the calculation of

reservoir parameters. As the control valve is opened, pressure falls to initial flowing pressure.  Point D: As fluids move up the drill pipe, pressure increases due to flow restrictions in tools. After a suitable time, the tool is shut-in and termed final flowing pressure.  Point E: Pressure then increases to final shut-in pressure ©2005 Abalt Solutions Limited. All rights reserved

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Drill Stem Testing Recommendations

Pressure

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 We have to consider that the main objective is to record good data. Therefore the DST must be planned to accommodate any specific situation.  FIRST FLOW: (5-15 minutes), the objective is to remove any excess pressure which may have resulted from setting the packers.  FIRST BUILD UP: (30-60 minutes)  SECOND FLOW: (60 minutes)  SECOND SHUT IN: ( from 30 minutes to several hours) finding out the transmissibility and other characteristics of the reservoir.

1

2

4 3

6 5

1. 2. 3. 4. 5. 6.

Going into the hole Initial flow period Initial shut -in period Final flow period Final shut-in period Coming out of the hole

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Drill Stem Testing Analysis methods: Horner’s Plot method to determine permeability Type curve matching method to account for wellbore storage. Kohlaas type curve matching to determine kh /  Correa & Ramey for multiphase environments Computer matching DST

Well Testing

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Injection Well Tests

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 Pressure transient testing during injection into a well.  Important for efficient planning & operation of both secondary and tertiary recovery projects.  For analysis, the mobility ratio of injected fluid and in situ fluids must be near unity. Mobility Ratio M= (k/)w (k/)o Ratio of mobility of the displacing (injected) fluid to the fluid being displaced.

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Injection Well Tests Procedure

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 Well Shut-in to allow pressure to stabilize at initial reservoir pressure pi.  Test begins at t=0 with constant injection rate ‘q’ (taken –ve).  For the constant rate, the injection bottom hole pressure Pwf is modelled.  Plot of BHP Pwf vs. logarithmic injection time ‘t ’ is plotted and forms a straight line with slope ‘m’.  Allows the estimate of formation permeability ‘ k’ and skin factor ‘s’.

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Step Rate Injectivity Testing 

Normally used to estimate formation or fracture parting pressure, which is the injection pressure that will initiate a fracture in an un- fractured well or extend an existing fracture.

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Parting pressure determined from the test is equivalent to fracture extension/propagation pressure in hydraulic fracturing.

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Helps determine that any injection above parting pressure will can result in pre-mature break through, poor sweep, reduced oil recovery etc.

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Procedure – Well shut- in before test begins .BHP nears static reservoir pressure. – Injection rate stabilized at reduced and constant rate,stabalization period should be long to achieve steady state or pseudo-steady state flow. – Injection rates are increased step wise.  In low permeability formations (k10 mD) injection rates of 30 mins is adequate. ©2005 Abalt Solutions Limited. All rights reserved

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Interference Tests  Involves creating pressure disturbances in one well and measuring the pressure response in the other wells.  Done by either producing from or injecting into at least one well, called active well, and observing the pressure response in another well called observation well.  Characteristics of pressure behaviour as function of time reflects the reservoir properties.

Well Testing

 Tests can be conducted with more than one active and more than one observation well.  These tests are ideal for establishing continuity of pay zone within the reservoir ,estimating volume of hydrocarbons within drainage area of wells and quantifying reservoir anisotropies.

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Interference Tests

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 Note that a time lag exists between the time when a rate change is made at active well and time when pressure transient is seen in the observation well.

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase

Well Testing

Pulse Tests  A coded signal is sent from an active well to a shut-in observation well.  Signal is generated by producing from or injecting into the active well, shutting in the well, producing again, shutting in again, and repeating in a regular pattern.  The well is pulsed so that we can identify effective of active well on pressure response at observation well amid noise of reservoir pressure trend.  Highly sensitive pressure gauges are used.  These tests can quantify directional reservoir properties, such as permeability.  Advantages – Fewer problems with reservoir noise & pressure trends that cause errors.

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Surface Test Equipments  Surface Test Tree – Used in DST operations and are four-way cross with four valves. – Surface test tree should be able to support the full string weight and all four valves should provide a seal with differential pres sure. – Surface test trees with have either a master or production wing valve or both, hydraulically operated. – Most trees include a swivel to allow pipe rotation to set packers during tests.

 Coflexip Hoses

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– High pressure hose used between surface trees & choke manifolds on tests conducted from floating rigs. – Allows good flexibility & better corrosion resistance.

 Rig permanent Pipe works – Information regarding line size, wall thickness, sour service, i nspection reports must be checked. – High and low pressure pipe works need to be present.

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INTRODUCTION TO HYDROCARBON EXPLOITATION Development Phase Surface Test Equipments  Hydraulic surface safety valve – Free standing valve incorporated for additional safety. – Used where long high pressure flow lines are used.

 Sand trap – Functions as sand separator during testing and used when excessive sand production is anticipated. – Consists of 2 vertical cylinders with screen meshes of varying s izes – Normally installed between flow head and choke manifold.

 Sand detection equipment – Has an intrusive probe set into the flow line. – Used to detect sand grains across multiphase flow conditions.

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 Data reader – Used to monitor wellhead pressure and temperatures and chemical injection upstream of choke.

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Surface Test Equipments  Other equipments Gauge tanks Surge tanks Transfer pumps Gas diverter manifold Oil diverter manifold Burners Flare lines Vent lines Emergency shut down systems Relief lines

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