Well Testing. Buildup Tests Drill Stem Test Production History and Decline Analysis

Transcription

1 Well Testing Buildup Tests Drill Stem Test Production History and Decline Analysis

2 Well Testing What Can it Tell You? Both drawdown and buildup tests are useful. Drawdown Well tests combined with production data can be very useful. Buildup What does a well test show? 1. Permeability 2. Damage 3. Depletion 4. Boundaries (sometimes)

3 Build Up Tests Some Basic Well Work Clues Using Derivatives Press Early Time Measuring wellbore, but not reservoir Damage indicated by difference Pressure Data Pressure Derivative Boundary indicator? Permeability Indication Dimensionless Time

4 Special Cases Dual Porosity System May be fractures and matrix or other combinations. Compartments?

5 Sources of Confusion in Testing Wellbore dynamics Liquids moving in and out of the wellbore, varying height of liquid during the tests and the small pressure differences caused by changes in liquid heights. Plugging: hydrates, scale, etc. Phase separation gas / liquids separate as well is shut in. Location of the pressure recorder in the wellbore with respect to the producing zone. Must account for pressure effect of distance of recorder from the producing zone. Wellbore vs. reservoir transients

6 Multilayer, Multi-Reservoir or?

7 What happens to the liquid column in a flowing well when the well is shut in? Two Cases Liquid Loaded Gas Well Dispersed Gas Lifted Oil Well

8 1. Density Segregation, 2. Pressure Buildup and 3. Liquids Forced Back in Formation Liquid Loading in Gas Well As shut-in pressure rises, the liquids may be forced back into the formation to an equilibrium height. This changes liquid level and the pressure differential between a gauge recorder and the formation. Phase Separation in Flowing Oil Well

9 From Drilling Kick Technology P S P S P S As a gas bubble rises in a closed liquid system, the bottom hole pressure, P BH, also rises since the bottom hole pressure is equal to the liquid gradient plus the pressure above it. Since the perforations are open in a well, the increasing pressure pushes the liquids back into the reservoir. P BH P BH P BH Change in liquid height may affect recorder readings if the gauge is above perfs.

10 1 After Shut-In, Downhole, When Gauge is set above the Perfs Pressure difference between the gauge and the perfs is the density of the fluid between them. Perfs

11 1 After Shut-In, Downhole, When Gauge is set above the Perfs Pressure difference between the gauge and the perfs is the density of the fluid between them. Perfs

12 2 Pressure Rising and Liquid Level Starting to Drop As long as the liquid is above the gauge, then gauge and perf pressures only separated by liquid density. Perfs Note that the pressure measured by the gauge (bottom) and the reservoir pressure are separated only by the liquid gradient.

13 3 Pressure Rising and Liquid Level Below the Gauge As liquid drops below the gauge, gas density, which is much less than liquid, affects the recorded pressure Perfs As the liquid drops below the gauge, the difference between gas and liquid must be used to adjust the gauge pressure back to the reservoir pressure.

14 4 All Liquid Forced Back into the Formation Gauge and reservoir read nearly the same when only gas is in the wellbore. Perfs As the liquid drops below the gauge, the difference between gas and liquid must be used to adjust the gauge pressure back to the reservoir pressure.

15 Now, what was this recording?

16 Add gradients to the curve. Reservoir pressure Gas Gradient Gauge reading Liquid Gradient

17 Now, What do you do with it? Look again at depletion analysis Is this really depletion? Look at the well test conditions and see what was in the wellbore at the start of the test and at the end. The only way to really tell if the depletion is genuine is to know what fluids and where the fluids were in the wellbore at the start and at the end of the tests.

18 Run Gradients at Start and End of a Well Test Gas, about 0.1 to 0.15 psi/ft (pressure dependent) Liquid, oil = psi/ft fresh water = 0.43 psi/ft brine = 0.52 psi/ft

19 Gradients at Start and End of a Buildup test

20 On a routine buildup test, how can permeability difference be recognized? Permeability

21 Note that the rate of change is continuously decreasing from the start of the test a way to spot anomalies. Permeability Higher perms build up fast, lower perms build up slow. Higher perm Lower Perm

22 What Causes Anomalies? Injection or other pressure support may increase pressure. Drainage of your acreage by an offset well may explain late time changes.

23 An increase in buildup pressure in the early time usually indicates phase redistribution a wellbore effect. Early Time Effects

24 Some Observations on Well Testing Not a reservoir effect if it happens suddenly Wellbore transients dominate over reservoir transients Draw wellbore schematic & see if wellbore fluid dynamics are affecting the test Run static wellbore gradient before & after. Run gradient to lowest perf. Differentiate between wellbore & reservoir effects.

25 Production Decline Analysis Assumptions Well Test Production Data Constant Rate Declining Rate Declining Pressure Constant Pressure

26 Differences Well Test Smooth, min. flux BH measurement High frequency Controlled test Expensive Not always available Short term Production Decline Noisy Surface measurement Averaged data Data sometimes poor Inexpensive Always available Long term

27 Type of Decline Analysis Exponential Not valid for transient flow (e.g., tight gas) Hyperbolic Harmonic

28 Constant Rate and Reservoir Transients Pressure Distribution represented by the curved lines. The transient portion occurs before the pressure distribution reaches the boundary at Pwf. When the boundary is reached, the flow is in pseudo-steady state flow (pressure at the wellbore falls at exactly the same rate as the reservoir pressure). Reservoir Boundary Wellbore Transient Pwf boundary Reservoir Boundary

29 Constant Pressure tied to Pwf As the pressure distribution or transients reach the boundary, the flow becomes boundary dominated.

30 Comparison of Constant Pressure and Constant Rate Plots Constant Rate Solution Harmonic Decline Constant Pressure Solution Exponential Decline

31 Material Balance, Normalized or Cumulative Production Time Actual Rate Decline Equivalent Const. Rate q Q Q Actual Time Dimensionless Time =Q/q (i.e., cum. Prod/rate)

32 Constant Pressure Solution Corrected by Material Balance Time

33 Transient Infinite acting Log q/dp Decreasing Skin Boundary Dominated Log Material Balance Time

34 Production Type Curves Transient Infinite acting Stimulated Well Log q/dp Boundary Dominated More Damaged Log Material Balance Time

35 Production Type Curves Transient Infinite acting Boundary Dominated Log q/dp Curve match in this area indicates pure volumetric depletion Log Material Balance Time

36 Production Type Curves Transient Infinite acting Boundary Dominated Log q/dp Data above the curve may indicate pressure support, layers, or compartments. Log Material Balance Time

37 Production Type Curves Transient Infinite acting Boundary Dominated Log q/dp Data below the curve may indicate liquid loading Log Material Balance Time

38 Production Type Curves Transient Infinite acting Boundary Dominated Log q/dp Transitional Effects Difficult to see events in this zone with production data Log Material Balance Time

39 Blasingame Curve Showing Damage Data set on type curve set matched on a flat line, but data set shows increasing rate with time a sure sign that a damaged well is slowly cleaning up.

40 Higher Permeability Well Pressure support Indicated by later time data

41 Agarwall-Gardner Type Curve Match of a Fractured Well Derivative. Shows successful fracture in a tight gas well.

42 Agarwal-Gardner Type Curve Method The A-G type curve method uses existing field production data to diagnose conditions of producing wells as well as reservoir properties and conditions This new method can be used to determine how effectively a well has been stimulated, the remaining available reserves, and to predict how long it will take to effectively produce them. The A-G type curve method can be used to predict a well s response to a work-over, a re-fracture treatment, a change in tubulars, or to quantify the effects of compression

43 Agarwal-Gardner Type Curve Method The A-G type curve method is based on rigorous, pressure transient analysis (PTA) methods. This technique makes special provisions to account for changes in well rates and depletion effects to maintain analysis accuracy over a wide range of well producing conditions and production times. The A-G type curve method uses special groupings of variables, to help distinguish between completion, reservoir, and well operating effects. Proper quantification of each of these effects, allows for more effective well interventions and for better field management.

44 1.E+04 1.E+03 1.E+02 1.E+01 1.E+00 1.E-01 1.E-02 1.E-03 1.E-04 1/PwD 1.E+01 1.E+00 1.E-01 1.E-02 1.E-03 1.E-04 1.E-05 Agarwal-Gardner Type Curve Method The A-G type curve method uses a suite of graphical type curves which can better ensure analysis accuracy and better predictive results: 1.E E+ 01 CfD= 500 CfD= E+ 02 CfD= 500 CfD= 500 Xe/Xf= 1 Xe/Xf= 2 Xe/Xf= 5 1.E+ 00 CfD= 0.5 CfD= CfD= E+ 01 CfD= 5. CfD= 5. CfD= 5. 1/PD 0.18 CfD= 0.5 CfD= 05 1.E GIP = 15.4 BCF 1.E+ 00 1/PD Xe/Xf= E-02 Xe/Xf= 1 Xe/Xf= 2 Xe/Xf= E-01 1.E-03 1 P D t D td Fig. 1: Reciprocal Dimensionless Pressure,, based on Xf vs. Dimensionless Time, GIP = 22.4 BCF GIP = 18.5 BCF re/rwa= 100 re/rwa= 1000 re/rwa= E-02 1 P D t DA Fig. 2: Reciprocal Dimensionless Pressure,, based on Area tda vs. Dimensionless Time, 0.04 re/rwa= 1.E Dimensionless Cumulative Production, QDA For better ease of data manipulation, software familiarity, and user convenience, the A-G type curve method has been implemented in MS Excel

45 Rate (MMSCF/D) Wattenberg Well Example Pbh (psia) Rate and Bottom Hole Pressure Daily Rate (MMSCF/D) Bottom Hole Pressure (psia) calc Pbh time (days) 0

46 A-G Excel SpreadSheet Rate (MMSCF/D) Program FINITE CONDUCTIVITY FRACTURE TYPE CURVES chart title >>>>>> WELLNAME: Example D, Wamsutter Well developer documentation: dcg "v xls " 10/27/1999 FINITE COND. FRAC. TYP E CURVES Tubing Le n ft Re s ults Only Enter Data in BLUE Number Boxes Tubing ID 2.2 in are a: 0.0 a cre s Red Numbers Are Calculated K: md Z(Pint): P initia l Black Numbers Are Optional Xf: fe e t m(pint): P initia l Values, optionally read from GASPRO.dat file Ne t Pay: 30.0 fe e t (ucg)i: P initia l Res. temp: F C Qd: #DIV/0! Hydrocarb' Poros ity: fraction C Td: 0.00E+00 Initial Pre s (BHo le): 5100 ps ia Xe / Xf: 0.00 Ca lc.'d OGIP: 0.00 BS CF SuPs T-C= N/A Ca lc.'d WH te mp: de g F Data-TC var= N/A Ca lc.'d Gas g rav: 0.68 (a ir=1.0) Indic ato r: 1 (0=BHP,>1=WHP) Works pa ce to Right --->>> Time Cumulative Daily Rate Input Pres Bottom Hole number of Pres s ure Vis cos ity z-factor number of (days ) Production (MMSCF/D) (ps ia); Pres s ure Prod. data (ps ia) If (c'pois e) is (dimenles s ) PVT Values (MMSCF) 0=BHP (ps ia) values GASPRO us ed, be thes e > 2=WHP (below) will Calc'd! E E E E corners of selection trapezoid r^2 OGIP: E E E E E E E E E E

47 qd 1.E+01 WELLNAME: Example D, Wamsutter Well K (md)= Fcd=500 Xf (ft)= Pinit (psia)= OGIP (BCF)= Area (ac)= Fcd=5 Xe/Xf= 5.00 SuPs T-C= XD5,FCD5. Data-TC var= 9.722E-02 1.E+00 Fcd=0.5 Fcd=0.05 Xe/Xf=25 1.E-01 Xe/Xf=5 Xe/Xf=1 Xe/Xf=2 1.E-02 1.E-02 1.E-01 1.E+00 1.E+01 1.E+02 1.E+03 td(xf)

48 Rate (MMSCF/D) Pbh (psia) Rate and Bottom Hole Pressure Daily Rate (MMSCF/D) Bottom Hole Pressure (psia) calc Pbh time (days) 0

49 Dimensionless Numbers used in A-G type curve Dimensionless Pressure/Rate Dimensionless Time Dimensionless Cumulative Dimensionless Fracture Conductivity/Length f reservoir f f CD x k w k = F T t q p m h k p g D D ) ( 1422 ) ( f e D x x = x ) ( = f g g D x t c t k t D DA DA p t Q ) ( ) ( p m h k T t q q p g D D D A t c t k t g g DA ) ( = ) ( ) ( 2 ) ( p m G z p Q t t c i i i g D D i ) ( ) )z( ( = 2 p t p p p pdp p(t) m i i i G Q t z p p z p ) ( 1 ) (

50 R p ini Reservoir pressure Depletion, Compaction, Perm Loss What has depletion to do with Well Productivity * R pal 1 2 Time Pressure maintenance = Increase Well Productivity Increase Recoverable Reserves Minimize Permeability Loss Minimize Compaction (1) Initial Reservoir pressure Maximum energy to drive production Maximum permeability Single phase production No depletion, No compaction, Min. formation stress Minimum production cost (2) Artificial lift required (gas lift, ESP, etc) Sharp increase in production cost Multi phase production > reduced saturation, loss of capilary pressure Loss of cohesive forces R paban Permeability (% of initial K) (3) Abandonment pressure Minimum energy to drive production Maximum depletion, compaction, formation stress Minimum remaining permeability * (SPE 56813, ) Reslink

51 Drill Stem Tests Diagnostics Application

52 The basic recording graph paper of an old style DST pressure in the well, recorded against time, usually on a clock that runs from the time the tool is switched on at the surface immediately before it starts into a well. Electronic advances have altered the appearance of the data, but the basics remain the same.

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