PRESSURE TRANSIENT ANALYSIS (EXAMPLE ANALYSIS HORIZONTAL WELL) SMITH OIL COMPANY JONES #1 BUILDUP 7/1/99 THRU 7/17/99 Job #00000

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1 PRESSURE TRANSIENT ANALYSIS (EXAMPLE ANALYSIS HORIZONTAL WELL) SMITH OIL COMPANY BUILDUP 7/1/99 THRU 7/17/99 Job #00000 The reports and plots contained herein are true and accurate representations of the input data; However, all interpretations are opinions based on analytical techniques described in the literature. ARC PRESSURE DATA, INC. cannot and does not, guarantee the accuracy or correctness of any interpretations. ARC PRESSURE DATA, INC. shall not, except in case of gross or willful negligence on our part, be liable or responsible for any loss, cost, damages, or expenses incurred or sustained resulting from any interpretations made by one of our officers, agents, or employees. Odessa, Texas Denton, Texas Sonora, Texas (800) (800) (915)

2 NORTH TEXAS FIELD DENTON COUNTY, TX BUILDUP TEST DATES: 7/1/99-7/17/99 JOB #00000 DISCUSSION OF RESULTS INTRODUCTION An analysis was performed on the buildup data collected from the above mentioned well by ARC PRESSURE DATA, INC. The main test objective is to determine reservoir pressure. Alternate objectives include the formation skin, effective well length producing and permeability. The well was flowing at an average rate MMcf/day GAS, 35.8 STB condensate/day, and STBW/day prior to shut-in. A net producing time near 276 hours was estimated based on the cumulative production and time since the well was stimulated. The condensate stream was recombined to give a total wet stream gas production based on a correlation by Gold et. al. SUMMARY OF RESULTS Based on the log-log and derivative curve the inner boundary is best described by the Decreasing Storage w/ (-Step Model). The middle-time region is modeled by the Radial Homogeneous model with no-flow upper and lower boundaries for a horizontal well completion. The late-time data exhibits behavior resembling a single no-flow boundary near the well. This upward kick in the data can also be attributed to a composite change in well properties due to the condensate fallout or due to the lack of sufficient producing time. Because there was no obvious early or late-time radial flow response during this test, a type-curve fit was the method of analysis. Linear flow was exhibited through most of the middle-time region. It was only interrupted by changing wellbore storage and wellbore effects. The results of the best fit to the horizontal well model gave an effective radial permeability to gas to be 0.26 md with a total skin of A very large vertical permeability to gas near 8.9 md shows evidence of excellent vertical communication, probably stemming from communication through natural or

3 drilling-induced fractures. An effective well length was determined to be 650 feet. This represents an analytical interpretation of the length of the lateral that is actually giving up production. The only sure way to verify this is through production logging, but this calculation has been supported by production logging results in other wells that we have been associated with. In order to derive this estimate, we made the assumption that the lateral penetrates the constant thickness about halfway over the whole length of the lateral. The extrapolated pressure, , is essentially an intrinsic extrapolation of the model match to an infinite time. Extrapolation of the linear flow plot during the boundary response gives a maximum pressure at the boundary at the instant of shut-in near A straight line through the linear flow portion of the test on the square-root plot yields an effective well length of 648 feet. This agrees very well with the type-curve results. Also this linear flow plot shows an approximate doubling of slope, indicating the presence of a single no-flow boundary response. DISCUSSION OF RESULTS The producing time was somewhat shorter than the actual shut-in time. This can lead to erroneous results, especially the late-time response. In essence, the boundary response we see could simply be the lack of drawdown time to stabilize the transient profile in all directions from the well. It is not uncommon to see radially composite changes in mobility in condensate wells. Overall, considering the number of parameters estimated, the analytical match is relatively good for this test. If you have any questions concerning the results of the analysis, please call me at (800) Regards, Bill Jones Well Test Analyst

4 SUMMARY OF RESULTS SMITH OIL COMPANY JOB #00000 NORTH TEXAS FIELD (RED RIVER) DENTON COUNTY, TX BUILDUP 7/1/99 TO 7/17/99 FLOW REGIME MODELS: Inner Boundary Model:...Decreasing Storage w/ (-Step Model) Middle- Region Model:...Radial Homogeneous Outer Boundary Model:...Infinite-Acting PRESSURE DISTRIBUTION: Datum Depth feet Initial Measured BHP Final Measured BHP Extrapolated (radius-of-influence) Pressure RESERVOIR PROPERTIES: Effective Permeability to Gas md Vertical Permeability to Main Phase md Effective Producing Length feet Dimensionless Placement of Lateral WELLBORE / NEAR WELLBORE CONDITION: Wellbore Storage Coefficient bbl/psi Skin Factor BOUNDARY CONDITIONS: Distance to No-Flow Boundary, L feet

5 100 Model Results Two no-flow boundaries - homogeneous Single fault Cs = bbl/psi Cd = V = bbl Lw = ft Log-Log Plot Delta m(p) (psi2/cp (*1E-06)) 10 1 Log-Log Plot Model Results Two no-flow boundaries - homogeneous - Single fault Stepped Wellbore Storage Wellbore storage coefficient Dimensionless wellbore storage Apparent wellbore volume Horizontal well length Log-Log Plot Line Details Line type : Linear flow through layer Slope : 0.5 Intercept : Coefficient of Determination : Not Used Line type : Wellbore storage Slope : 1 Intercept : Coefficient of Determination : Not Used Number of Intersections = 0 TP1 Pressure Radial Deriv Equivalent (hours) - Tp=276.0 Value bbl/psi bbl ft ARC PRESSURE DATA, INC. - PERMIAN BASIN REGION

6 Linear Flow Plot TP1 Pressure 350 m(p) (psi2/cp (*1E-06)) : APPROXIMATE DOUBLING OF SLOPE Model Results Two no-flow boundaries - homogeneous Single fault Lw = ft Lw.h = ft2 Sconv = P* = Tandem Square-root Function - Tp=276.0 Linear Flow Plot Model Results Two no-flow boundaries - homogeneous - Single fault Stepped Wellbore Storage Horizontal well length Well length/layer thickness product Convergence skin Extrapolated pressure Linear Flow Plot Line Details Line type : Linear flow through layer Slope : Intercept : Coefficient of Determination : Extrapolated m(p) Extrapolated pressure Value ft e4 ft Linear flow through layer psi2/cp (*1E-06) Line type : Free model line Slope : Intercept : Coefficient of Determination : Not Used ARC PRESSURE DATA, INC. - PERMIAN BASIN REGION

7 Extrapolated m(p) Extrapolated pressure Number of Intersections = 0 SMITH OIL COMPANY Free model line psi2/cp (*1E-06) ARC PRESSURE DATA, INC. - PERMIAN BASIN REGION

8 Delta m(p) (psi2/cp (*1E-06)) Match Results Two no-flow boundaries - homogeneous Single fault Kz = md K = md Zwd = 0.5 decimal fraction Cs = bbl/psi Cs2 = bbl/psi Tc = 0.05 hr S = Lw = ft D = 0 1/(Mscf/day) L = ft Type Curve Plot Equivalent (hours) - Tp=276.0 Type Curve Plot Model Results Two no-flow boundaries - homogeneous - Single fault Pressure Radial Deriv Stepped Wellbore Storage Vertical permeability Permeability Horizontal well position Value md md ARC PRESSURE DATA, INC. - PERMIAN BASIN REGION

9 m(p) (psi2/cp (*1E-06)) Radial Flow Plot - MODEL MATCH OVERLAY Quick Match Results Two no-flow boundaries - homogeneous Single fault Constant compressibility Cs = bbl/psi Cs2 = bbl/psi Tc = 0.05 hr K = md Kz = md S = Zwd = 0.5 decimal fraction Lw = ft D = 0 1/(Mscf/day) L NF = ft Pi = Gen pressure TP1 Pressure Horner Function - Tp=276.0 Quick Match Results Two no-flow boundaries - homogeneous - Single fault Stepped Wellbore Storage Wellbore storage coefficient Second Wellbore Storage Change for Second Storage Permeability Vertical permeability Skin factor Horizontal well position Horizontal well length Rate dependent skin coefficient (D) Boundary configuration distance : L NF Computed initial pressure Value bbl/psi bbl/psi hr md md ft /(Mscf/day) ft ARC PRESSURE DATA, INC. - PERMIAN BASIN REGION

10 Reservoir Description Fluid type : Condensate Well orientation : Horizontal Number of wells : 1 Number of layers : 1 Layer Parameters Data Formation thickness Average formation porosity Water saturation Gas saturation Formation compressibility Total system compressibility Layer pressure Temperature Well Parameters Data SMITH OIL COMPANY Layer ft e-6 psi e-4 psi deg F Well radius Distance from observation to active well Wellbore storage coefficient Storage Amplitude Storage Constant Second Wellbore Storage Change for Second Storage Well offset - x direction Well offset - y direction Fluid Parameters Data Gas gravity Condensate gravity Condensate/Gas ratio Water-Gas ratio Water salinity Check Pressure Check Temperature Gas density Initial gas viscosity Gas formation volume factor Water density Water viscosity Water formation volume factor Initial Z-factor Initial Gas compressibility Water compressibility Well ft ft bbl/psi psi hr bbl/psi hr 0.00 ft 0.00 ft Layer sp grav API STB/MMscf STB/MMscf e4 ppm deg F lb/ft cp e-3 ft3/scf lb/ft cp RB/STB e-4 psi e-6 psi-1 ARC PRESSURE DATA, INC. - PERMIAN BASIN REGION Page 1 of 8

11 Fluid Parameters Data (cont) Layer 1 Separator Pressure Separator Temperature deg F Vapourising volume ratio scf/stb Wet stream gravity sp grav Wet stream rate multiplier Layer 1 Correlations Ug Correlation : Carr et al Vap Vol Correlation : Gold et al Layer Boundaries Data Layer 1 Boundary Type : Single fault L1 Boundary : No-flow L1 L2 L3 L4 Drainage area Dietz shape factor Layer ft ft ft ft acres Layer 1 Model Data Layer 1 Model Type : Two no-flow boundaries - homogeneous Permeability Skin factor (Well 1) Vertical permeability Horizontal well length Horizontal well position Rate dependent skin coefficient (D) RD1 EX3 Data Files Layer md md ft /(Mscf/day) ARC PRESSURE DATA, INC. - PERMIAN BASIN REGION Page 2 of 8

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17 Rate Change Data Pressure Rate MMscf/day SMITH OIL COMPANY ARC PRESSURE DATA, INC. - PERMIAN BASIN REGION Page 8 of 8