Basic Welltesting For Dst Supv

WELL TESTING (Pressure Transient Test)

RESERVOIR ENGINEERING DEPT. PERTAMINA EP REGION JAWA

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TYPICAL USE OF WELL TESTING

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BASIC REASON FOR TESTING A WELL

1. To obtain a physical sample of the fluids produced from the reservoir; 2. To obtain a measured flow rate indicative of the productivity of the formation; 3. To obtain pressure data for the calculation of reservoir parameters t and d for f the th recognition iti off natural t l or induced i d d anomalies around the borehole.

WELLTEST PLAN PACKAGE 1. STATEMENT OF TEST OBJECTIVES Specify p y whyy the well is being g tested and what is the expectation to achieves from the test data. 2. PROPOSED TEST DESIGN Specificy type of test to be run; flow rates, duration, periods; shut-in h t i periods i d and d times; ti th contingency the ti procedures d i the in th event that the test has to be altered in the field because of mechanical problems. 3 MECHANICAL DESIGN 3. Specify required surface and subsurface mechanical system. Included Test interval and landing locations, well completion diagram, surface test facilities (meter system, and the way in which hi h the th produced d d fluids fl id are to t be b disposed) di d) . 4. INSTRUMENTATION Specify pressure and temperature measuring and recording devices (with backup as needed) as well as the wire line recommendations. 5. SAMPLING Specify sampling fluids: how many samples to take, when,

Objektif ‘Well Testing’ (Press. Transient Test): 9 Karakterisasi Reservoir 9 9 9 9 9 9

Tekanan Dasar Sumur / Reservoir Permeabilitas Reservoir Flow Effisiensi Drajat Kerusakan formasi (DR, (DR S) Type / System Porositas (single / Double i.e. Storage & Capacity ) Model Daerah Reservoir (Luas & Bentuk daerah Pengurasan )

9

Reservoir boundary’ (type, jarak & arah)

2 Potensi 2. P t i Reservoir R i -

Produktivitas / Injektivitas (PI / II) HC inplace (Well base OOIP or OGIP) HC Deliverability (AOFP etc)

Prinsip kerja : Mencatat respon reservoir thd gangguan yang diberikan melalui sumur [email protected]

Type ‘Well Testing’ ((Ref. Teknis Operasional) p )

1. Konventional Testing -

Press. Build-Up test P Press. D Drawdown d Test T t

2. Multi Rate Test -

Two Rate T R t test t t Four Point test (Gas) (Modified) Isochronal Test

3. Multiple Well Testing - Interfference Test Pulse Test

4. Drill StemTest (DST) [email protected]

PERALATAN UJI 1. -

Peralatan Atas / Permukaan Wireline Unit Lubricator Group BOP Group Test Unit

2. -

Peralatan bawah Permukaan Bottomhole Press. Gauge B tt h l Temp. Bottomhole T Gauge G Bottomhole fluid sampler

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DOWNHOLE PRESS. - TEMP. GAUGE 1. -

MECHANICAL Amerada P-T P T Bomb type

2.

Electronic Memmory Gauge (EMR) - Strain /Capacitance Gauge - Quartz gauge

3. -

Surface Press-Temp Read Out (SPRO) Standard Quartz gauge Crystal Quartz gauge

(GEOSERVICES GAUGE)

Mechanical gauge These selfcontained gauges have three essential components: a pressurepressure sensing device, a pressure-time recorder, and a mechanical clock. The pressure element of a mechanical gauge is normally a multiple-coil Bourdon-tube Bourdon tube type

Electrical memory gauge In most of these gauges a transducer converts pressure into an electrical signal that is recorded downhole. Pressure data are available only after a gauge has been retrieved to surface.

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Sistim Monitoring Perekaman Data

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Well Testing / Pressure Analysis Press Press. TransientTransient Test Analysis Method (Methode) 1. Horner Plot -

Semilog (Tp + ∆t) / ∆t

2. Pressure Derivative (Type Curve match) - Log-log -

dP/dt

3. Simulasi [email protected]

Integrated Linier & Log-Log Analysis

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Work Flow ‘Simulation method’ P Press. T Transient i tT Testt A Analysis l i

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‘Typical Generic Model’ Press. Transient Test Analysis

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‘Geological Model illustration’ Press. Transient Test Analysis

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Deliveriverability Test analysis

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Inflow Performance Relationship

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WELL TESTING ANALYSIS ~ HORNER’S PLOT In a Well testing, the flow period is about the same duration as the shut-in period, and so pressure buildup data must be analyzed with the Horner plot, pws versus log[(tp l [(t + dt)/dt] If the shut-in period is long enough, and if wellbore storage is not dominant, a Horner plot of buildup should have a straight-line section with slope —m, where permeability calculated as :

Or transmissibility The skin Th ki ffactor t iis estimated ti t d ffrom th the ffollowing ll i empirical i i l equation ti ffor a di dimensionless value s denoting "skin factor."

The term log[(tp+1)/tp] is normally neglected when tp» 1 or when the skin f t is factor i high. hi h

damage ratio (DR), (DR) which compares flow rate observed on a DST (q0) to the theoretical flow rate without damage (qt).

An equation for calculation of DR based on the skin factor is related to the equation

DR substantially greater than 1.0 indicates damage. Eq. can be simplified by assigning average values to formation parameters. This produced an equation for estimated damage ratio (EDR):

An equation for calculation of DR based on the skin factor relation is reported as

where pressure drop across the skin is computed as

Initial or average pressure p is estimated by extrapolating the Horner straight line to infinite shut-in time (tp + dt)/dt = 1. 1 Both the first buildup plot and the second buildup plot extrapolate to the same static or initial pressure.

For practical purpose, the radius of investigation during DST is equivalent to the radius of drainage given by :

The following equation from Van Poollen may be used to estimate the radius of investigation of a particular DST in an infinite radial flow system:

EXAMPLE : ANALYSIS DST USING HORNER PLOT A well testing was conducted on an oil well well. The following information was reported by the DST Company. The pressure buildup data are given in tables. Determine the following:

• Check validity and consistency of ‘WT’ data • • • • • • •

Formation permeability, k Ski ffactor Skin t and d pressure drop d d due tto skin ki Initial reservoir pressure Flow efficiency Damage ratio A Apparent t wellbore llb radius di Radius of investigation

DST DATA : Test type = open hole Total well depth = 6550 ft h = 17ft; rw = 0.33 ft; Poro = 16%; Viso = 1.O cP API = 36.87 API; ct = 8.0 x 10'6PSi^-1; Bo = 1.215rb/stb Vu = 0.0197 bbl/ft and p = 52.78 lb/ft3 M dd Mud density it — 7.51b/gal 7 51b/ l Gauge depth = 6549 ft Hole size = 7.88 in; Pipe length = 240 ft; Collar length = 240 ft; Diameter of collar = 4.5 in. Reservoir pressure @ gauge depth = 2560 psi Pressure at the end of first flow = 371 psi First flow period = 6min First shut-in period = 30 min Second flow period = 60 min Second shut-in period = 120 min Initial shut-in pressure = 2660 psi Final shut-in pressure = 1005 psi Pressure at the end of second flow period = 643 psi Final shut-in pressure = 1969 psi

SOLUTION To analyze pressure buildup test, follow these steps: • Identify the MTR and find the slope of MTR, MTR p1hr, p1hr and p p* of the Horner plot of the second shut-in period. • Prepare Horner plot of the first and second shut-in buildup pressures on the same graph.

CHECK VALIDITY AND CONSISTENCY OF REPORTED DST DATA.

Hydrostatic pressure = 6549 x 0.390 = 2554 psi The reported initial reservoir pressure at gauge depth is 2560 psi, which is in good agreement with pi = p* = 2554 psi (extrapolated pressure from the first shut-in straight line). The mud weight should be :

Thus the reported mud weight is correct

L Log-log l data d t plot. l t

S il Horner Semilog H plot l t for f data. d t

From the extrapolated MTR, line of the second shut-in to (tp + dt)/dt = 1 pi = p* = 2550 psi.

DST (DRILL STEM TEST) ~ UKL Method of temporary completing a well to determine the productive characteristics of a specific p p zone byy p provided primarily indication of formation fluid content and data to help evaluate productivity of the zone, completion practices, estimate formation properties and well bore damage.

ESTIMATED RESERVOIR CHARACTERISTICS FROM DST ANALYSIS

DST Tools

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DST Tools Evolution

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DST S STRIP S CHART C

Good DST data should :

RUNNING DST

DST Typical Chart Interpretation

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DST Typical Chart Interpretation

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DST Strip Chart Identification a) Packer failed and could not be set set. b) Runaway clock. Clock spring released. c) Tool failed to close. No buildup is obtained. d) Tool failed to Open. e) Clock stopped at shut-in drillstem normal. normal f)

Effect of large superpressure. Pressure buildup during flow and buildup period,

g) No formation permeability small amount of mud may be recovered, h) Low Low-permeability permeability formation. formation

RECOMMENDATION FOR FLOW AND SHUT-IN TIME FOR DST Knoval Oilwell Testing

no

ACTIVITY

DURATION

1

1 t Fl 1st Flow

5 15 mntt 5-15

2

1st Buildup

30-60 mnt

3

2 d Flow 2nd Fl

4

2nd Buildup

GOAL Remove any excess pressure which may have h resulted lt d from f setting tti the th packer. Get reliable initial reservoir pressure.

60 mntt

Evaluate formation characteristic for some distance from the well.

30 mnt to several hours.

Calculate transmissibility and other reservoir characteristics.

COM PARING EKSTRAPOLATED 2ND BUILDUP PRESSURE WITH INITIAL BUILDUP PRESSURE INDICATE THE SIZ E OF THE RESERVOIR.

CHECKING VALIDITY AND CONSISTENCY FOR DST REPORTING DATA

1. Calculate the hydrostatic mud pressure and check agains recorded initial and final hydrostatic mud pressure. Mud Gradient (psi/ft) = 0.433 / 8.33 x ppg mud weight. Hydraulic Pressure (psi) = Well depth (ft) x Mud Gradient. Mud Weight = Hydrostatic Press x Depth x (8.33/0.433) 2. Check with reported mud weight. 3. Check accuracy of Pi (estimated from extrapolated MTR Line of the second shut-in to (tp+dt)/dt = 1.

ESTIMATION OF AVERAGE FLOW RATE (DST)

1. 2. 3.

CALCULATE MUD GRADIENT PSIFT MGR = MUD WEIGHT (PPG) * 0.433/8.333 ESTIMATED FEET OF MUD FOM = INITIAL SHUT SHUT-IN IN PRESSURE AT THE END OF 1 ST FLOW / MGR CALCULATE CAPACITY OF DRILL COLLAR. CDR = Cs * RHO /144 WHERE Cs WELLBORE STORAGE = 25.65* Awb(ft^2) /Rho (lb /ft3) Awb = Phi * Rp^2 …. Rp = ID Drill Collar Collar. Rho = fluid density (lb/ft^3) = 141.5 /(131.5 + SG)

4.

ESTIMATE FLUID PRODUCED FROM FORMATION FPF FPR = CDR * FOM …. (FT)

5.

CALCULATE INITIAL FLOW RATE QI = FPF / (FLOWTIME * 1440 MIN/DAY) …..STBPD

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