Shut-in Conditions Research Articles

Synergic Kinetic Inhibition Effect of EMIM-Cl + PVP on CO2 Hydrate Formation

Kinetic hydrate inhibitors (KHIs) are employed to mitigate gas hydrate formation in pipelines at low concentrations. Ionic liquids and conventional available KHIs (polymers) perform poorly at high subcooling and extended shut-in conditions. Thus, it's necessary to understand the inhibition mechanism and performance of mix kinetic inhibitors for gas hydrate mitigation in oil and gas transmission lines. In this work, the synergic kinetic inhibition effect of 1-Ethyl-3-methy-limidazolium chloride (EMIM-Cl) + Polyvinylpyrrolidone (PVP) on the induction time and gas uptake during carbon dioxide (CO2) gas hydrate formation is reported. The study was performed in a high pressure sapphire cell at a pressure and temperature of 36 Bar and 1 oC respectively using an isochoric constant cooling method. Result suggests that, the induction time of deionized water + carbon dioxide hydrate increased over 100% in the presence of pure EMIM-Cl and PVP, with PVP slightly higher than EMIM-Cl comparatively. Surprisingly, a significant reductions in CO2 hydrate inhibition performance is observed in the presence of EMIM-Cl + PVP studied synergic systems compared to their inhibition in pure state.

The Return of Kinetic Hydrate Inhibitors

Kinetic hydrate inhibitors (KHIs) have been serving the petroleum industry for many years. They are normally used at dose rates of <3% of the produced water, resulting in considerable savings in CAPEX/OPEX. However, several uncertainties and challenges have prevented their more widespread usage, including a lack of consistent test protocols, poor repeatability of test results, concerns over performance under shut-in conditions, the potential risk of hydrate formation at the top of the pipelines, and relatively low cloud points/fouling issues, which can cause problems in produced water handling/reinjection (PWRI) and/or monoethylene glycol (MEG) regeneration schemes. In this communication, we present the latest developments related to KHIs, including the results of a testing technique based on crystal growth inhibition that produces reliable and repeatable results, KHI performance under shut-in conditions, risk of hydrates at the top of pipelines, and a technique for removing KHIs from produced water prior...

Modeling Transient Wellbore Temperature During Diagnostic Fracture Injection Tests

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166120, ’Modeling Wellbore Transient Fluid Temperature and Pressure During Diagnostic Fracture Injection Testing in Unconventional Reservoirs,’ by B. Nojabaei, SPE, The Pennsylvania State University, A.R. Hasan, SPE, Texas A&amp;M University, and C.S. Kabir, SPE, Hess, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. Diagnostic fracture injection tests (DFITs) have gained widespread usage in the evaluation of unconventional reservoirs. In typical field operations, pressure is measured at the wellhead, not at the bottom of the hole. The bottomhole pressure (BHP) is obtained by adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. One can question the soundness of this practice because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. This paper offers an analytical model for estimating the transient temperature at a given depth and timestep, for computing the BHP. Temperature Model During Pressure-Falloff Test After a well is shut in at the surface, afterflow at the sandface is negligible because of low formation permeability. Upon cessation of injection, the cold injection water begins to gain heat from the surroundings. Heat transfer during flowing and shut-in conditions has been modeled with an energy-balance equation, accounting for various resistances to heat transfer. The resulting differential equations are solved numerically. However, with robust assumptions, an analytical expression can be developed for transient fluid temperature during falloff. The heat flow from the formation into the wellbore raises the internal energy of the fluid and of the composite tubing/casing/ cement material. Please see the complete paper for the quantitative expression. Field Example Modeling Temperature Transient During Falloff Test. The pressure-computation algorithm entails two steps. First, the temperature is evaluated as a function of time at various depths throughout the wellbore. As expected, the temperature at well bottom will exhibit the largest excursion. Second, the fluid properties of density and compressibility are evaluated at each depth step corresponding to the temperature profile, leading to the BHP estimation at a given timestep.

Catastrophic Crystal Growth of Clathrate Hydrate with a Simulated Natural Gas System during a Pipeline Shut-In Condition

This paper presents a significant finding where capillary-aided catastrophic gas hydrate growth is observed under a shut-in condition (static fluid) for an uninhibited system. With the use of a newly designed apparatus, consisting of six units of identical rocking cell, nucleation and growth are observed. All experiments are conducted under isochoric conditions using 11.0 K subcooling (ΔTsub) as a driving force. A simulated natural gas mixture of 90.0 mol % methane + 10.0% mol % propane is used as a gas phase. The liquid phase used is 3% (Na+, Cl–) brine. The observations of the capillary-aided mass-transport mechanism for a catastrophic gas hydrate growth are presented in this work. Our observations show hydrate crystal formation at a brine wetted area close to the brine/gas interface initiates capillary-aided catastrophic hydrate growth. Moreover, no mass transfer restriction of brine toward catastrophic gas hydrate growth is observed. Furthermore, our results show the denser (less porous appearance) hydrate structures are continuously displaced from the hydrate–water interface (hydrate growth side). This displacement allowed new hydrate crystals to be formed uninterruptedly until the exhaustion of water in the cells. On the basis of macroscopic observations, the capillary-aided mass-transport mechanism for a catastrophic gas hydrate growth is presented.

A New Approach in Pressure Transient Analysis Part I: Improved Diagnosis of Flow Regimes in Oil and Gas Wells

One important limitation of pressure derivatives is diagnosing flow regimes in wells with high water cut and flowing conditions (Drawdown) because the well production are never stable due to surface operating constraint including multiphase metering problem and fluid compressibility, hence most drawdown are not easily interpretable due to noisy data. In some cases where the data are useful, the derivative data are always noisy and difficult to interpret, resulting in the application of deconvolution and various smoothing techniques to obtain a perceived representative model which often time might not. This paper introduces a new statistical method for diagnosing flow regime for both flowing and shut-in conditions. The method utilize the second differencing of pressure and time parameters since pressure change and subsurface flow rate is non-stationary and then integrate the residual pressure differences using simple statistical tools such as sum of square error SSE, moving average MA and covariance of data to formulate the statistical derivative model. The model is tested with constant pressure, constant rate conditions and also in well with high water production Results from three scenarios investigated shows the statistical derivative display distinctive radial flow fingerprint as the conventional pressure derivative with clear reservoir features revealed with high degree of accuracy. It demonstrated that for high water production well, a good radial stabilization can be identified for good permeability estimation without smoothing the data. It also showed that in all three scenarios, the drawdown radial fingerprint can be replicated in the build-up pressure responses, hence a good match of the data. The approach also reduces the derivative noise in the radial flowing period for better interpretation of flow regimes.

Crystal Growth Inhibition Studies for the Qualification of a Kinetic Hydrate Inhibitor under Flowing and Shut-In Conditions

One of the methods to control the formation of hydrates in oil and gas pipelines is the injection of kinetic hydrate inhibitors (KHIs). The accepted understanding is that KHIs slow down or interfere with hydrate nucleation, forcing an extended “induction time” (time to emergence of viable hydrate crystals) at a given subcooling. As a result, KHIs are commonly evaluated by measuring induction times in the laboratory. However, this experimental approach has some limitations, notably in that data can be stochastic due to the nucleation element, raising questions over reliability/transferability, with multiple repeats often required to establish clear trends. As KHIs also exhibit powerful growth inhibition properties, a new crystal growth inhibition (CGI) method for the evaluation of KHIs has been previously developed with the aim of providing a means to more rapidly evaluate KHIs in a robust manner. This method shows that KHIs induce a number of well-defined hydrate CGI regions with different growth rates as...

Gas Recovery From Tight Sands: Impact of Capillarity

SummaryHydraulic-fracturing operations carried out by injecting large volumes of water cause invasion of the injected water into the formation and create a water block. The flow of gas toward the wellbore/fracture during production will result in the removal of the water block through viscous displacement, as well as evaporation, that occurs because of gas expansion over a long period of time. However, some observations from the field show that the productivity of hydraulically fractured tight gas wells improves after a period of shut-in, leading to a speculation as to whether capillary suction is responsible for the cleanup of water block that eventually leads to productivity improvement. In this work, we use laboratory-scale experiments and modeling to find that capillary-driven transport is an important mechanism that helps redistribute water within the tight gas rock sample. Without capillarity, the model underpredicts the effective gas relative permeability recovery in the laboratory sample. We also find, using simulations, that capillary transport has the effect of enhancing the overall evaporation rate of water from the rock core. The model for calculating saturation changes and the effective gas relative permeability is complete with regard to all the mechanisms, such as displacement and evaporation. This is unlike previous studies, which did not include one or the other.Field-scale-simulation study of gas flowback using the new integrated model shows that the effective gas relative permeability of the invaded zone is significantly affected by capillary suction. In the absence of capillary suction, displacement and evaporation proceed as usual, but the invaded-zone water saturation does not dissipate quickly enough. The fracture-face skin, which is a function of the effective gas relative permeability, decreases faster as the invaded zone water is redistributed because of capillary suction. The simulations show that the evaporation of water from the invaded zone is very slow because of the low gas-flow rates in the tight rock matrix. In comparison to evaporative removal of water from the invaded zone, capillary-suction removal is significantly higher and faster.A sensitivity study on fracture-face skin shows that capillary suction has a significant effect on the cleanup at low drawdowns and smaller invasion depths. At complete shut-in conditions, the invaded-zone saturation continues to dissipate because of capillary suction. This confirms the general observation and anecdotal evidence that tight-sandstone wells produce at greater gas-flow rates after a period of shut-in. The methods described in this study can be adapted to perhaps determine the duration of such shut-in periods. Additionally, the models can be used to rigorously predict gas-production rates from a fractured well, including capillary effects, without resorting to averaging concepts such as fracture-face skin.

Feasibility Study for the Use of Kinetic Hydrate Inhibitors in Deep-Water Drilling Fluids

The feasibility of using kinetic hydrate inhibitors (KHIs) in deep-water water-based drilling fluids to give added subcooling protection has been investigated. A range of neutral, anionic, or cationic commercial and noncommercial KHIs were first tested for their compatibility with highly saline drilling fluids. Thereafter, the most suitable products were tested as KHIs in a sapphire cell arrangement at pressures up to 300 bar and temperatures down to 0.9 °C. Experiments with the best inhibitors were also carried out in the presence of two types of clay to represent drilling cuttings with different activity and in simulated shut-in conditions. The conclusion was that some KHIs, particularly neutral or anionic polymers, could be used in drilling fluids if the activity of the clay/cuttings is low, probably because of negligible adsorption of the KHI polymer onto the clay/cuttings. It was also shown that pressure and not just subcooling is an important factor in determining the performance of a KHI.

Gas-condensate well test results interpretation at Helang field

Gas condensate reservoirs exhibit a complex behavior caused by the existence of two-fluid system, reservoir gas and liquid condensate, around the well when bottomhole pressure drops below the dew point. Numerous published literatures (Gringarten et al., Marhaendrajana, Raghavan) based on field data have demonstrated that when this happens, two different mobility regions can be observed in the pressure derivative response in well test data. These two mobility regions are (1) an outer region away from the well, with initial liquid condensate saturation and (2) a region near to the well, with increasing condensate saturation and corresponding lower gas mobility. Some laboratory/theoretical data (Boom et al., Mott et al.) even showed an additional third region : (3) a region in the immediate vicinity of the well with high capillary number corresponding to reduced condensate saturation and higher gas mobility.In Helang gas condensate field, offshore Sarawak, East Malaysia, multiple wells were tested in year 2004 and again in year 2005. Modified isochronal tests (MIT) were conducted in each productive zone with bottomhole shutin condition. This report investigates the identification of 2-region radial composite model from the analyses of Helang field 2004/2005 well test data. Furthermore, the existence of the high capillary number region (region 3) is also investigated from the well test data. With the availability of well test data from two time periods, this report also examines the possible growth of the liquid condensate drop-out region versus time.

Thermal Behavior During Restart of Ultradeepwater Flowlines

Summary For subsea tiebacks in ultradeep water, restarting from shut-in conditions can pose significant flow-assurance issues, particularly with respect to hydrate formation. Achievable restart rates are a function of available hydrate inhibition and shut-in conditions. The overall chemical volume required is highly dependent upon the tieback type, length, and insulation level. Current practice is to evaluate alternate procedures, such as preheating the flowline to reduce warm-up times and chemical requirements.

TEMLOPI/V.2: a computer program for estimation of fully transient temperatures in geothermal wells during circulation and shut-in

This paper describes the development, validation and application of the TEMLOPI/V.2 computer program. This program is a useful tool for estimating in-situ the transient temperature distribution of the fluids employed for drilling geothermal wells. TEMLOPI/V.2 is based on a mathematical model which is developed to consider two-dimensional transient heat transfer during drilling and shut-in conditions in and around a geothermal well. The solution of the partial differential equations is based on the finite-difference technique with an implicit scheme. This scheme serves to demonstrate the numerical solution procedure. Each radial grid node is placed in a different thermal region: flow inside the pipe, metal pipe wall, flow inside annulus, and the surrounding formation. The program was written in FORTRAN 77 using modular programming and runs on most IBM compatible personal computers. The software code, its architecture, input and output files, the solution algorithm, flow diagrams and source programs are described in detail. From validation tests, computed temperatures differ by less than 5°C from analytically obtained temperatures. Comparison of results from the fully transient TEMLOPI/V.2 simulator and the pseudo-transient version, TEMLOPI/V.1, with measured data shows that the fully transient model provides better results. Application of TEMLOPI/V.2 is demonstrated in a practical application study of well EAZ-2 from Los Azufres Mexican geothermal field.

Effect of P– ρ– T behavior of muds on loss/gain during high-temperature deep-well drilling

High-pressure and high-temperature deep-well drilling is associated with several unusual problems. A recent report on one such well in the North Sea indicated an apparent partial mud loss during circulation and a pit gain after stopping the circulation. When the well was shut-in on gain, a pressure buildup was observed at the surface. In the present study, an attempt is made to explain these observations quantitatively with the help of pressure–density–temperature ( P– ρ– T) behavior of mud and the temperature changes in a static mud column. An analytical method is developed to estimate the maximum pit gain when the linear temperature profile of wellbore changes from that immediately after circulation to geothermal. To estimate the maximum rise in pressure if the well is shut-in during these temperature changes, an analytical method is outlined. An approximate relationship between the gain and lapsed time after circulation is proposed. Estimated maximum gains for an example well are of the order of a few tens of barrels for both water- and oil-based muds. In general, estimated maximum gains in the case of oil-based muds are nearly twice that for water-based muds of identical densities. It is also shown that the maximum rise in surface pressure under shut-in condition which is of the order of a fraction of one ppg, is approximately equivalent to the decrease in static bottomhole pressure under open condition.

Estimation of Temperatures in Geothermal Wells During Circulation and Shut-in in the Presence of Lost Circulation

The estimation of temperatures in and around a geothermal well during circulation, and during shut-in conditions in the presence of lost circulation is presented in this work. Estimated temperatures are compared with temperature logs measured during drilling stoppages. Temperatures were estimatted using a computer code specifically developed to account for the transient convective heat transfer due to lost circulation in the rock surrounding a well. This feature of the present code is important since wellbore simulators normally consider the heat transfer process in the rock as a merely conductive problem. The code is capable of accounting for these losses at any point in the well and application was made to the study of two Mexican geothermal wells(well LV-3 from the Las Tres Virgenes field and well EAZ-2 from the Los Azufres field). The results show that the effect of lost circulation on the shut-in temperature profiles can be modelled satisfactorily. Research is under way to improve the present methodology.

Trials of Threshold Hydrate Inhibitors in the Ravenspurn to Cleeton Line

Summary A series of field trials to test threshold hydrate inhibitors (THI's) has been carried out in the wet gas line connecting the Ravenspurn and Cleeton fields. These BP-operated assets are located in the U.K. sector of the southern North Sea, approximately 50 miles offshore of the Dimlington gas terminal. The flow line is 13 miles long, 16 in. in diameter with a normal production rate of 195 MMscf/D. During the trial, the line pressure was maintained at 75 barg (1,088 psig) for a throughput of 90 MMscf/D. When methanol injection into the line was stopped, hydrates readily formed. Conditions in the line were 8 to 9°C inside the equilibrium hydrate curve. This resulted in an estimated 50 tonnes of hydrate accumulating in the line over a 4-day period. At these same conditions, THI injected at a dose rate of 3,000 to 5,000 ppm (parts per million on the basis of total water production) prevented hydrate formation. After 6 days, the chemical supply was exhausted, and after a delay during which chemical was flushed from the system, hydrates formed as before. The robustness of the chemical to line shut-in conditions was also confirmed. These trials conclusively show that a low dosage chemical can be used for hydrate suppression in a wet gas pipeline system.

Interference And Pulse Test Analysis By Nonlinear Regression

Abstract A nonlinear regression technique based on the method of least squares is developed for pulse lest analysis. The values of the transmissivity, kh// µ and storativity h Φc, that minimize the sum of squares of differences between observed and calculated pressures are determined. The equations that represent the conditions for minimum are solved by an iterative procedure based Oil a combination of the Newton-Raphson and the Regula-falsi methods. The pressure at any point is estimated using the line-source solution and the principle of superposition. The method can be used for the analysis of pulse testing of equal and unequal periods as well as cases that could not be analyzed by the tangent construction method of the conventional pulse testing methods. Such cases include situations of unequal pulse ratio and variable flow rate in the different cycles. The method is applicable for the general case of multiple-rate interference testing with pulse testing as a special case. The developed method was tested using simulated data. The method was found to converge rapidly. Excellent agreement was found between the assumed and estimated parameters for the different cases tested. Introduction Pulse testing is being widely considered as a method for obtaining interwell reservoir properties such as porosity and permeability(1–3). In pulse testing, the rate at an active welt is periodically changed between flowing and shut-in conditions while the pressure response at an observation well is recorded. The data is then analyzed graphically by drawing tangents to the pressure-time curve and determining the time lag and the pressure response amplitude of the different odd and even cycles. A set of correlations published by Kamal and Brigham(3) is then used to estimate the transmissivity, kh/ µ and storativity h Φc. Recently, Ogbe and Brigham(4) presented a method to correct for the skin and wellbore storage effects. They also found it necessary to correct the previously published Kamal-Brigham correlation curves. Moreover, the use of these correlations is limited to cases of constant pulse ratio, constant flow rate and constant cycle length of the different cycles. Cases where the lengths of the pulse and/or shut-in periods or flow rates are different in the different cycles cannot be analyzed by the conventional tangent construction method. Furthermore, the conventional graphical method cannot be used in a computer-based systematic analysis which is most desirable. Some attempts were made to apply the methods of regression analysis for the determination of reservoir characteristics from well test data (5–7). These methods, however, are coupled with numerical reservoir simulators that solve the diffusivity equation. For a presumably homogeneous reservoir for which an analytical solution exists, such methods are unnecessarily complicated. In a previous work, the method of least squares was applied for interference test analysis in the cases of constant rate and two rate tests(8). In this work, the method of least squares is used to develop a procedure for the analysis of the general case of multiplerate interference testing which includes pulse testing as a special case.

Two-Step Rate Test: New Procedure for Determining Formation Parting Pressure

Summary. A reliable estimate of the formation parting or fracture extension pressure is important for efficient operation of waterfloods and tertiary recovery projects. A new procedure, called a two-step rate test procedure, called a two-step rate test (2-SRT), is presented for determining this pressure. Unlike a conventional step rate test (SRT), which consists of several constant-rate injection steps, the 2-SRT requires only two injection steps, during which pressures are measured continuously. Test procedure, design and analysis procedure, design and analysis considerations, and recommendations for test implementation are provided. Field examples are included. The 2-SRT procedure offers potential for time procedure offers potential for time and cost savings over a conventional SRT. Introduction Rapid water breakthrough in production wells as a direct result of exceeding a certain critical injection pressure in nearby injection wells was observed as early as 1945. This critical injection pressure is called the formation or fracture parting pressure (FPP). The FPP is equivalent to the "fracture extension/propagation pressure" in the hydraulic fracturing literature. Several studies recently demonstrated that a fracture will continue to propagate if injection is above the FPP and the injection/ withdrawal ratio is greater than one. In addition to this uncontrolled fracture extension, injection above the FPP may also cause fracturing out of pay. These factors may lead to premature breakthrough of injected fluids, poor sweep efficiency, reduced recovery, poor sweep efficiency, reduced recovery, and loss of costly injection fluids. On the other hand, injection far below the FPP may result in injection volumes much lower than the allowable maximum and a reduced rate of oil recovery. A reliable estimate of the FPP is therefore critical in conducting secondary and tertiary recovery projects. The SRT has been the primary method used for several years to determine FPP. A recent paper provided a detailed discussion of the design and analysis of SRT'S. To define the FPP adequately from an SRT, several (usually seven or more) constant-rate injection steps, generally of equal duration, are needed. Further, the duration of each step (also referred to as timestep size) should ideally be long enough for the data to be free of wellbore-storage effects. If continuous pressure measurements are available during pressure measurements are available during an SRT, the data can be analyzed by multiple-rate superposition methods to determine the FPP. The Odeh and Jones superposition method or Agarwal's multirate equivalent time analysis can be used to analyze SRT data. Ref. 7 gives a detailed discussion of the proper application of multiple-rate analysis and identification of FPP from such an analysis. This paper describes a new test procedure (2-SRT) for determining FPP. The 2-SRT requires only two constant-rate steps, during which pressure and time data are measured continuously and analyzed for determination of the FPP by multiple-rate superposition methods. Pressure data from the two steps are compared on Agarwal's multiple-rate equivalent-time basis. Guidelines for the design and analysis of a 2-SRT and recommendations regarding the test implementation are provided. Field examples are included to demonstrate the applicability of this procedure. procedure. Discussion Test Procedure. The 2-SRT can be run in at least four different modes shown schematically in Fig. 1. For each mode, the test well is either shut in or stabilized at a constant injection rate before the start of the test. In either case, the stabilized pressure before the 2-SRT must be below the FPP. Modes 1 through 3 refer to cases where the well is stabilized at a constant injection rate before the test is run. Mode 4 is the case when the well is shut in at the time of the test. The 2-SRT procedure for each mode is described below. Mode 1. The injection well is shut in for Step 1, followed by injection at a high constant rate for Step 2. The injection rate for Step 2 is chosen such that the FPP will be exceeded. Mode 2. If the well is on a stabilized low-rate injection, Step 1 of the test may be stepping up the injection rate to a constant value that is still low enough so that the FPP is not exceeded. The injection rate is then further increased to a higher constant rate for Step 2. Mode 3. The injection is reduced to a lower constant rate for Step 1 and then increased to a higher constant rate for Step 2. Mode 4. The well is stabilized at shut-in conditions. The 2-SRT consists of two constant-rate injection steps with a stepwise increase in the injection rate for each step. For all the modes of the 2-SRT procedure, it is extremely important that the pressures attained for the entire duration of Step 1 are below the FPP. The injection rate for Step 2 is chosen such that the injection pressure will exceed the FPP during this step. JPT P. 84

Wellhead Innovations for Hot High-Pressure Wells

Summary Mobil Oil Indonesia's (MOI's) Arun wells produce gas A rates up to 150 MMscf/D (4.25 × 10 6 M 3 /d). The gas contains 14 % CO2, and up to 100 ppm H2S. The Rowing wellhead temperature is about 325deg. F (163deg.C). The original shut-in surface pressure was 5,800 psi (40 MPa). Failure of the resilient wellhead casing seals occurred in about 40% of the wells. This was attributed primarily to the effects of high flowing wellhead primarily to the effects of high flowing wellhead temperatures and to temperature cycling between flowing and shut-in conditions. MOI decided that a metal to metal seal, between the 9%-in. (24.5-cm) casing long string and wellhead, was required to ensure a long-term effective wellhead seal for Arun producing conditions. Wellhead metal-to-metal seals of the size and type required for 9 5/8%-in. (24.5-cm) casing did not exist anywhere in the industry. We worked with the manufacturers of the wellheads used in Arun who designed, tested, and manufactured metal-to-metal wellhead seals. Special tools were developed to field-machine the casing so that an effective metal-to-metal seal is obtained between the casing and the wellhead. Arun Field Arun field is one of the largest gas fields in the world. It is in the rice-growing area of North Sumatra about 8.7 miles (14 km) from the coast (Fig. 1). The field was discovered by MOI in 1971 in the Bee Block Contract Area in Aceh Province, North Sumatra. The structure is about 11.5 miles long and 3. 1 miles wide (18 1/2 km long and 5 km wide) wide a productive area of about 23,400 acres (94.7 × 10 6 M 2 ). The reservoir is a carbonate reef. The top of the reef averages about 9,800 ft (2990 m) subsea. Both the original reservoir pressure of 7,100 psi (49 MPa) and the reservoir temperature of 352deg. F (178deg.C) are abnormally high. The hydrocarbon well stream contains 13.8 mol% CO2, 5.9 mol% water, 50 to 100 ppm H2S, and traces of mercury. About 45 to 50 bbl/MMscf (0.00028 m 3 /std M3) of condensate are produced with the gas. produced with the gas. Producing wells, production facilities, and compression facilities are placed in clusters where the produced fluids are cooled, dehydrated, and separated (Fig. 2). Excess produced gas is compressed and injected into a number of downdip injection wells. Gas and condensate flow through separate pipelines to Pertamina's liquefied natural gas (LNG) plant on the Pertamina's liquefied natural gas (LNG) plant on the coast near Lho Seumawe for processing, liquefaction, and export. Design of Arun Wells The Arun formation is a thick, highly productive carbonate reef. To take advantage of this productivity, 7-in. (17.8-cm) tubing was chosen. A diagram of the original producing wells is shown in Fig. 3. The casing strings of producing wells is shown in Fig. 3. The casing strings of 20-, 13%-, and 9%-in. (50.8-, 34.0-, and 24.5-cm) are run and cemented to the surface. Original Design of Arun Wellheads (Fig. 4) The Arun well producing conditions are among the most severe in the world. The original reservoir pressure was 7,100 psi (49 N4Pa) at an average depth of 10,000 ft (3050 m), and the reservoir temperature is 352deg. F (178deg.C). The wells are designed to produce at rates of 150 to 175 MMscf/D (4.25 × 106 M3 /d to 5.0x 106 M3/d) with 45 to 50bbl/MMscf 0.00028 M3 /std M3) Of condensate. The original surface wellhead pressures were 5,800 psi (40 MPa) shut-in and 4,900 psi (34 MPa) flowing. The surface temperatures range from 100deg.F (38deg. C) when the well is shut in, to 325deg. F (163deg. C) when the well is flowing, to 80deg. F (27deg. C) when the well is being treated. JPT p. 284

Well-Test Analysis for Wells Producing From Two Commingled Zones of Unequal Thickness

Established methods of analyzing pressure buildup for two-layer no-crossflow systems are extended here to include the effect of the thickness of each zone for a wide range of permeability ratios. In addition, methods are presented for estimating the permeability of the individual layers. Introduction In 1961, Lefkovitz et al. presented solutions describing the pressure behavior of a well producing at a constant rate from a bounded, producing at a constant rate from a bounded, noncommunicating multilayer reservoir. Their study provided a basis for pressure test analysis of wells producing from commingled zones. They recommended a Homer graph for determining average formation flow capacity but found it unsatisfactory for the evaluation of mean or average reservoir pressure. As a result, they suggested that the pressure. As a result, they suggested that the Muskat graph be used to calculate the static reservoir pressure. More recently Cobb et al., using the results of Lefkovitz et al., examined the pressure behavior of a two-layer reservoir for a wide range of producing and shut-in conditions. They assumed that each zone was of equal thickness and they presented results along lines suggested by the general pressure buildup theory for a wide range of permeability ratios. An important conclusion of Ref. 4 was that the permeability and thickness of each individual layer permeability and thickness of each individual layer cannot be evaluated by the conventional semilog techniques. Accordingly, they recommended that an independent effort be made to determine the individual layer characteristics. The primary objective of this paper is to extend the pressure buildup analysis of wells producing from two commingled zones by including the effect of the thickness of each zone for a wide range of permeability ratios. The results presented in this paper correspond to thickness ratios of 2 and 5. It will be shown that the results may also be used to analyze reservoirs with thickness ratios of 1/2 and 1/5, provided the permeability ratio is less than or equal to 10. The permeability ratio is less than or equal to 10. The second objective of this paper is to present methods for estimating the permeability of the individual layers. These methods may also be applied to earlier work related to two-layer commingled fluid production. We consider here a two-layer reservoir that is horizontal and cylindrical; it is enclosed at the top, bottom, and at the external drainage radius by an impermeable boundary. Each layer is homogeneous and is filled with a fluid of small and constant compressibility. The pressure gradients are small, and gravity effects are negligible in the reservoir. The porosity of the layers is assumed to be equal; the porosity of the layers is assumed to be equal; the permeability and thickness of the two zones are the permeability and thickness of the two zones are the parameters under investigation. The initial reservoir parameters under investigation. The initial reservoir pressure is the same in both layers and the surface pressure is the same in both layers and the surface production rate is constant. Finally, it is also assumed production rate is constant. Finally, it is also assumed that the instantaneous sand-face pressure is identical in both layers. Analysis of Dimensionless Pressure And Time Data For convenience of discussion we shall use the dimensionless variables listed below, defined in English engineering units. JPT P. 1035