Ambastha, A.K., and Ramey Jr., H.J., Stanford U. (USA)
Reservoirs with a fluid bank, or a burning front, reservoirs with a reduced or an increased permeability region around the wellbore, and geothermal reservoirs are often modeled as composite reservoirs. Reservoirs with a fluid bank include reservoirs undergoing waterflood, chemical flood, polymer flood, CO2 flood, and steam injection. Eight well tests reported in the literature exhibiting composite reservoir behavior have been analyzed using the deviation time method. The dimensionless deviation times obtained from pressure and pressure derivative responses for a well in a composite reservoir have been used for analyzing the well tests. Analysis shows the estimate of discontinuity radius to be sensitive to both the real and the dimensionless deviation times used. The estimated discontinuity radius from the deviation time method may represent a lower bound for discontinuity radius, if the swept region is not cylindrical. Also, obtaining an accurate deviation time for small mobility contrasts may be difficult. Limitations on the deviation time method due to wellbore storage effects have been quantified indicating a need to minimize wellbore storage in composite reservoir well tests. The effects of a transition region on the dimensionless deviation time have been studied using an analytical solution for a three-region reservoir.
A two-region composite reservoir is made up of two concentric regions of differing hydraulic diffusivities. Figure 1 shows a schematic diagram of a two-region composite reservoir. The inner and outer regions of a composite reservoir have different, but uniform, rock and fluid properties, and are separated by a discontinuity. Reservoirs with a fluid bank, or a burning front, reservoirs with a reduced or an increased permeability region around the wellbore, and geothermal reservoirs with thermal discontinuities or boiling regions are often modeled as composite systems. Reservoirs with a fluid band include reservoirs undergoing waterflood, chemical flood, polymer flood, CO2 miscible flood, and steam injection.
A well test in a composite reservoir exhibits wellbore storage effects, a first semi-log line corresponding to the inner region mobility, a long transition, and a second semi-log line corresponding to the outer region mobility, in sequence. The first and the second semi-log lines may be masked by wellbore storage and outer boundary effects, respectively. However, if the first semi-log line develops, a deviation time, , from the first semi-log line may be obtained. This deviation time can be used to estimate discontinuity radius by:
where t is in hours, and t is the dimensionless deviation time based on discontinuity radius. The variable R is the discontinuity radius in feet. The term, , is the hydraulic diffusivity of the inner region in md-psi/cp. Equation (1) is the basis of the deviation time method to estimate discontinuity radius. Other methods to estimate discontinuity radius or swept volume are: the intersection time method, the pseudosteady state method, and the type-curve matching method. The deviation time method requires the least amount of data for analysis.
DIMENSIONLESS DEVIATION TIME
Previous investigators have proposed a number of values for dimensionless deviation time. Dimensionless deviation time values were derived by either the drainage-radius concept, or a graphical analysis of numerical or analytical pressure responses from composite reservoirs. A summary of dimensionless deviation times proposed by several authors is presented in Table 1. Sosa et al. used the average dimensionless deviation time of 0.389 proposed by Merrill et al. (Table 1) to analyze simulated falloff tests in water injection wells.
Satman et al. and Tang used the Eggenschwiler et al. analytical solution, and graphed in ( ) as a function of to correlate the pressure responses for all discontinuity radii to the response for RD = 500. The choice RD = 500 is arbitrary, and is given by:
Ambastha and Ramey correlated the pressure derivative responses for all discontinuity radii by graphing a semi-log pressure pressure derivative as a function of . Figure 2 shows the semi-log pressure derivative responses from the Eggenschwiler et al. solution for several values of mobility and storativity ratios, and , respectively, given by (3)
Wellbore storage is neglected in generating the pressure derivative responses shown of Fig. 2. Figure 2 applies for non-zero skin values, as the pressure derivative is independent of skin, if wellbore storage is zero.
Waterfall, K.W., Sarawak Shell Bhd. (Malaysia)
Effectiveness of Enhanced Safety Management
Sarawak Shell Berhad (SSB) and Sabah Shell Petroleum Company (SSPC) are oil and gas exploration and production Companies working under a Production Sharing Contract (PSC) for PETRONAS. They operate or control the activities of Drilling-Rigs, Barges, vessels and approximately 100 Production Facilities offshore Sarawak and Sabah. Additionally they operate three onshore oil and gas terminals to treat the products prior to export.
Current production levels are in the order of 200,000 bbl/day of oil and 1000 million scf/day of gas. The Company employs some 3,000 Company personnel and approximately 2,600 contractor employees. With this spread of activities and this number of people there are many areas and operations being conducted on a daily basis which have the potential for accidents to occur. Whilst the programme and procedures stated in this paper are generally applicable throughout the Shell Group the references to Shell should be construed in this context as being relevant to SSB/SSPC activities only.
Shell has always been conscious of the need for improved safety and reduction of the risk of accidents throughout its operations and in 1984 it embarked on an intensive campaign of Enhanced Safety Management (ESM), which is modelled on the approach taken by Du Pont Organisation. Du Pont are the world renowned leaders in Safety Management and extensive use was made of their Safety Consultancy Division to establish Shell's ESM Programme. This programme has brought about a major improvement in Safety performance which is both sustainable and ongoing. Experience has shown that we can summarize the essentials of ESM to be:
a) Duty of care for the employees and the business. b) Line responsibility and accountability. c) People.......... not things (whilst high equipment standards are necessary it is our experience that people and their actions cause 80% of all accidents) d) No compromises
Once a safety policy is established it must be rigidly enforced in all of the following aspects:
1) Clear communicated Safety Policy. 2) Visible Management Commitment. 3) Full acceptance of Line responsibility and accountability. 4) Competent Safety Organisation. 5) Specific safety targets. 6) Clear and understood rules/procedures/standards. 7) Structured Design Safety Control. 8) Frequent inspection/audits. 9) Training. 10) Complete accident reporting/investigation/ measurement/learning. 11) Continued motivation and communication.
This policy and its enforcement has resulted in a reduction of accident frequency for Shell Companies which is still continuing.
This paper will deal with the way that ESM is implemented in Shell Companies and also with how we control our process designs to control our operations and so minimise the risk of major accident occurrence.
RELATIONSHIP OF MAJOR AND MINOR ACCIDENTS
The diagram below indicates the relationship between fatal accidents, less serious injuries and situations which could result in an accident. Many minor events when combined have the potential to result in a fatal accident and even cause calamities such as Chernobyl, Bhopal and Flixborough.
It is not possible to predict in advance when a fatal accident is going to occur or how to prevent it. Only by eliminating all unsafe acts and conditions can we be sure to prevent accident and injury and our Enhanced Safety Management Policy aims to do just that.
Hui, S.K., and Pillai, H., Esso Production Malaysia Inc. (Malaysia)
Two oil fields which are characterized by weak natural pressure support and unfavorable rock properties were planned for waterflooding by Esso Production Malaysia, Incorporated. This paper documents the collection and analysis of data for selection of an optimum waterflood pattern. Included will be discussions on parameters that affect short and long term water injectivity, extensive use of numerical models to compare alternate waterflood patterns, on-site production/injectivity tests to validate predictions and injectivity enhancement methods. With a going-in development plan for an inverted 7-spot waterflood pattern, the final optimum plan was assessed to be a combination of 5-spot and peripheral injection.
The Guntong and Tabu fields are located in the South China Sea, 210 kilometers off the east coast of Peninsular Malaysia in water depths of about 65 meters (Figure 1). Esso Production Malaysia Incorporated (EPMI) has explored and is currently developing the fields as a contractor to Petroleum Nasional Berhad (PETRONAS), the Malaysian national oil company.
Two major north-south trending faults divide the Guntong and Tabu structures into three areas (Figures 2 and 3). At Guntong the fault separating the west fault block from the remainder of the field is interpreted to be sealing. However, there is currently no conclusive evidence that the central fault block is separated from the east fault block. At Tabu there is no conclusive evidence that either of the two north-south trending faults are sealing. This paper will focus on the waterflood development program for the central and east fault blocks at Guntong and the east fault block at Tabu.
The majority of the oil-in-place at Guntong is contained in 6 main group I sandstone reservoirs. During the exploration phase large gas caps were encountered in the west fault block but only a small gas cap was intersected in the east in one of the lower I reservoirs. Consequently, gas caps are expected to be small or non-existent in the remaining east fault block group I reservoirs. Natural water-drive is expected to be weak. Oil-water relative permeability data from core samples show very low relative permeability to water at residual oil saturation. The oil is typified by a high API gravity, low viscosity and high gas-oil ratio. At Tabu, the east fault block group I reservoirs have similar characteristics. Waterflood was deemed to be most appropriate for development of the central and east fault blocks of Guntong and the east fault block of Tabu. Three 32-conductor platforms were planned for Guntong central and east fault blocks while one 32-conductor platform was planned for Tabu east fault block.
EPMI's previous field development experience had been with the groups J and K sandstone which typically have better reservoir qualities complemented by strong to moderate gas, water or combination drives. The task was to develop an efficient waterflood plan for the two fields.
The Guntong field is a east-west trending compressional anticline, approximately 11 kilometers long and 6.5 kilometers wide. The areal closure is about 50 square kilometers and the maximum structural relief is about 280 meters at the I-25 level in the east fault block. The maximum vertical relief in the west fault block is about 220 meters. The structure is asymmetrical, with dips of 5 deg. to 6 deg. on the north flank and 10 deg. to 14 deg. on the south flank. Figure 4 shows an east to west structural cross-section of the main group I sandstone reservoirs.
Mead, H.N., Homar Engineering Consultants Inc. (USA)
The Rectangular Hyperbolic Method (RHM) is a special type curve analysis for buildups and fall-offs. It is an analysis of the linear plot of shut-in time versus shut-in bottomhole pressure from instant of shut-in. No other plots, such as semilog or log-log, are needed. Neither is it necessary to use the superposition principle nor dimensionless constants. The RHM is based upon the proven fact that it is possible to obtain reasonable solutions to basic reservoir parameters for buildups and fall-offs using a finite, radial system model for the calculations. Skin can also be calculated. The skin in this instance is assumed to be a wellbore surface restriction phenomenon which will include turbulent flow near the wellbore, well damage, etc. Negative skin is the result of EFF Rw being greater than actual Rw. All models to date, both finite and infinite, are based upon an undersaturated reservoir entirely uniform in all aspects, with the wellbore open to, and only to, the entire reservoir thickness.
However, reservoirs are not usually uniform. There may be impermeable streaks or barriers which are extensive. The reservoir outline may not be circular. The reservoir may be what is called a dual porosity system, which usually means that the flow into the wellbore may be through vugs or fractures being fed, with reservoir fluid, from the matrix. We believe it is possible to make a simple model of a dual porosity system which can be used for solving for effective reservoir parameters. This study is an attempt to simplify reservoir analysis for a complex type of reservoir.
The purpose of this paper is threefold: (1) to present a method of buildup analysis (RHM) that can determine the percentage of reservoir column open to the wellbore which is contributing reservoir fluid, (2) to determine the average permeability of the permeable portion of the reservoir open to the wellbore and (3) to determine the possible existence of a dual porosity system and the characteristics of the fracture or vugular system that might produce reservoir fluid into the wellbore. Since RHM is a relatively new concept, two appendices are attached to explain the general aspects of the RHM procedure. The writer presented a paper related to this one at the 1987 SPE Regional California Meeting in April, 1987, (see reference 4).
This paper is based on: 1) finite system, steady state equations, either already proved in the literature or those presented in empirical form, and 2) the RHM approach. These data are shown and developed in Appendices A and B attached. Appendix A presents those finite system, steady state equations already proved and in the literature and the development of three additional empirical equations for determining effective radius of drainage (Rd) and equivalent reservoir thickness (Eq H) at the effective radius of drainage of both a vertical and a horizontal fracture. A theoretical finite reservoir is presented and analyzed in Table A1 to show the intimate relationship between RHM and a finite system. Appendix B presents a complete development of the factors on which RHM is based and how it is possible to determine percentage of reservoir thickness open to the wellbore which is actually producing reservoir fluid into the well. This percentage can either be greater or less than 100%. When it is greater than 100%, it is an indication that spherical flow is dominant. When it is less than 100%, it is an indication that for some reason the entire zone open to the wellbore is not producing fluid into the well.
A general statement of theory, and definitions is first presented to explain the background for using RHM to obtain additional information on dual porosity systems.
Then four examples are shown to demonstrate some of the factors involved in analyzing dual porosity reservoir systems by RHM. Example 1 points out the limited information in a dual porosity system that is available on a short time initial test. The only additional information to be obtained is the percentage of open reservoir producing into the well. In Example 2 the well was produced long enough before shutting in for buildup so that it was possible to determine effective fracture width and radius, average effective fracture permeability, average effective matrix porosity and effective matrix permeability into the sides of the fracture. In Example 3 it was found that the entire interval open to the wellbore was contributing to flow.
Atlantic Richfield Indonesia, Inc., brought five of seven platforms of the BIMA Field on stream in December, 1986. At the time of writing this paper, two additional platforms were being started up. Forty eight wells were drilled from the seven platforms, including sixteen horizontal (90) and high angle (85) wells drilled through the productive zone. All of the wells in the field were equipped with electric submersible pumps.
The early phase of the high angle well program was the subject of a paper presented to the 15th Annual Indonesian Petroleum Association in October, 1986. This update describes the transition from the original high angle well design to a horizontal well configuration and the use of downhole steering and directional control techniques to accomplish productive zone extended reach penetration lengths of up to 2173' with only a 19' TVD variation.
This paper also describes how measurement while drilling (MWD) technology was employed to obtain well directional and lithological data and also how MWD logs replaced drill pipe conveyed logging tools. The costs to drill and complete BIMA extended reach wells are shown to compare favorably with standard deviated holes.
Operating characteristics and problems encountered in the course of producing wells in the high angle and horizontal environment at BIMA are discussed. Early indications from production data analysis verify that high angle wells exhibit a reduced drawdown, as expected, meaning that reservoir management techniques to control water and gas coning can be applied without sacrificing oil rate.
Completions are described which illustrate how pump installations and wireline activities are limited to the upper sections of the high angle holes. Also described are techniques which will use novel workover engineering approaches in an attempt to control excessive water and gas influx in horizontal wells.
High angle wells have proven to be an economically practical approach in a complex reservoir such as the Batu Raja limestone in the BIMA Field. Atlantic Richfield Indonesia, Inc., has led the way in successfully drilling and operating these long reach wells in the Offshore N.W. Java contract area.
The development drilling phase of the overall BIMA Field project resulted in an evolutionary series of changes to the original high angle drilling plan. These changes were based upon the learned experiences of several successful high angle (85 +/-) holes drilled in the field. Drilling practices employed during the final phase of the high angle well development drilling program incorporated a high confidence level in planning and drilling long (up to 2173' MD at 90), horizontal drainholes through the thin (average 35' TVD thick productive zone; top is at -2550'), loosely consolidated Batu Raja limestone.
What began as a bold plan to drill 85 degrees +/- angle wellbores through the Batu Raja limestone became a series of mechanical successes in drilling 90 holes using conventional drilling technology. At the completion of the BIMA development drilling program, Atlantic Richfield Indonesia, Inc., had succeeded in drilling over 18,200' of horizontal hole in eleven wells and 4200' of hole at angles from 85 to 90 in five wells.
In order to minimize the tubing corrosion during production in a gas well, it is necessary to determine the factors such as wettability of tubing and critical erosional velocity etc. for the design of tubing corrosion prevention. The purpose of this work is to study the phase behavior of the production fluid in a production tubing in connection with the flowing velocity and wettability of tubing. Data from a CO2-rich offshore gas well of Taiwan are analyzed by a procedure developed in this study. It is shown by our calculation that the tubing in the well should not be corroded seriously during production because the tubing inner wall is oil-wet and the flowing velocities are much less than the critical erosional velocities.
A gas reservoir may be filled with natural gases, water, and possibly water vapor, condensate vapor saturated in natural gases may condense due to changes in pressure and temperature in the production tubing. The water and carbon dioxide may form carbonic acid which is corrosive to the tubing wall. The degree of tubing corrosion is affected by two major factors: (1) the wettability of the tubing wall; (2) the tubing flowing velocity. The wettability of tubing is determined by the amount of water and oil (condensate) adhering to the tubing wall. The amount of condensed water and oil is related to the phase behavior of flowing fluids in tubing. The pressure in tubing, playing an important role in the phase behavior, is varied with the production rate which is in turn related to the tubing flowing velocity. Therefore, two factors mentioned above have close relation with phase behavior of production fluids.
Determination of the phase behavior can provide information for locating the occurrence of condensed oil and water which are important for the possibility of forming carbonic acid and for determining the wettability of tubing. In addition, a critical erosional velocity, a threshold value to increase tubing corrosion rate of a factor of four, should be estimated for the production control to prevent tubing corrosion.
The purpose of this work is to study the phase behavior of the production fluid in a production tubing and to determine the wettability of tubing, critical erosional velocity, and flowing velocities for corrosion control. The result of the study is intended to provide key information for corrosion prevention design.
In order to estimate the amount of condensed oil and water in tubing, it is necessary to determine the flowing pressure distribution. The pressure distribution in tubing can be calculated by the equation suggested by Cullender and Smith for a vertical well.
Productivity of a Horizontal Well
Copyright 1988 Society of Petroleum Engineers, Inc.
This paper was prepared for presentation at the 63rd Annual Technical Conference and Exhibition of the Society of Petroleum Engineers held in Houston, TX, October 2-5, 1988.
This paper was selected for presentation by an SPE Program Committee following information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper Is presented. Write Publications Manager, SPE, P.O. Box 833836, Richardson, TX 75083-3836. Telex, 730989 SPEDAL.
Two appendices describe the mathematical and algebraic details that led to the formulas provided in the text of this paper. Appendix A presents the general solution, and briefly describes the techniques for deriving simple, closed form expressions for single, double, and triple sums of infinite series. Appendix B describes these procedures in a little more detail, and also indicates certain methods for averaging the variable wellbore pressures in the general anisotropic cases.
Uniform Flux Boundary Condition
For well problems similar to the one treated in this paper, a uniform flux, or a uniform pressure is commonly imposed as a boundary condition at the well surface. Recognizing that neither is entirely correct, the question that has been debated is whether one is preferable to the other, or whether both give satisfactorily accurate solutions. Muskat showed that the uniform flux boundary condition gives values accurate to 0.5 percent. We also investigated the implication of the uniform flux assumption. We used our exact solution (Equations A1-A3) and computed the wellbore pressure, Pwf at various locations y along the well length L. We did this for isotropic and anisotropic systems where the wells were located at the center, or away from the center. For the anisotropic runs the value of kx was equal to, or twice as large as, that of ky, and was ten times that of kz. Also L/b=0.5. We found that the maximum variation in Pwf values was 7 psi for the worst case. This was the anisotropic case with kx=2ky, kx=10kz, and the well was located away from the center.
Sutan-Assin, T. (Mobil Oil Indonesia) | Rastogi, S.C. (Mobil Oil Indonesia) | Abdullah, M. (Mobil Oil Indonesia) | Hidayat, D. (BKKA - Pertamina (Indonesia)) | Bette, S. (Mobil R and D Corp. (USA)) | Heineman, R.F. (Mobil R and D Corp. (USA))
This paper describes the simulation of the Arun gas condensate reservoir using Mobil's fully compositional simulator, COSMOS (Compositional System Mobil Oil Simulator). The reservoir is a Miocene carbonate reef complex which occurs at a depth of approximately 10.000 feet, and is up to 1,000 feet thick in some areas. The Arun reservoir is a compositionally dynamic system. The purpose of this simulation study was to predict future reservoir performance under various demand scenarios and optimize gas and NGL recovery. The simulation mode utilizes the recovery. The simulation mode utilizes the Peng-Robinson equation of state to account for the compositionally dynamic behavior of the reservoir in predictions of future performance. The equation of state was modified by Mobil to incorporate special features for Arun such as water vaporization in the reservoir under high temperature conditions.
A significant amount of time was spent on the geologic description of the field and initial data preparation, of the field and initial data preparation, which contributed to a good match of the historical data. The simulation model will serve as a reservoir management and planning tool to evaluate future operating strategies in the field. The technology presented in this paper is applicable to the management of other gas condensate reservoirs which exhibit physical phenomenal such as retrograde condensation, revaporization, and water vaporization.
The Arun Field is located on the northern coast of Aceh Province in North Sumatra. The field was discovered in 1971 and is a giant gas condensate reservoir. Mobil Oil Indonesia operates the field as a Production Sharing Contractor for Pertamina. Gas is produced from the Arun Limestone at a depth of approximately 10,000 feet subsea. The gas pay is up to 1,000 thick in some areas. The initial reservoir pressure was 7,100 psig at the datum of 10,050 feet subsea, and is consequently overpressured. The temperature is 352 deg. F at this datum. At discovery, the reservoir was above the dew point, and had a stabilized condensate/gas ratio of about 48 STB/MMscf of water-free wellstream gas. The reservoir is underlain by an aquifer with a gas-water contact at about 10,600 feet subsea. Reservoir fluid properties and average rock properties and given in Table 1.
The Arun Field began production in 1977. Field development was based on a cluster concept whereby only small areas of land are required for surface production and drilling facilities. This was done to minimize surface disruption to native farming and to the local community. There are four clusters in the field, each cluster designed to contain a maximum of sixteen wells. Producing wells are drilled directionally from these clusters. The gas is produced under a gas cycling scheme to maximize condensate recovery. Currently, there are ten gas injection wells located on the downdip perimeter of the field. The gas and condensate are delivered to the P.T. Arun LNG Plant for processing and liquefaction prior to export (Figure 1).
The field production at present is about 2700 MMscf/D of separator gas, of which 800 MMscf/D are reinjected, 35 MMscf/D are used for fuel in the field, land 1865 MMscf/D are delivered to a 42-inch gas pipeline to supply two fertilizer plants and the P.T. Arun LNG Plant. About 135,000 bbl/d of unstabilized condensate are delivered to the P.T. Arun LNG Plant through a 20-inch pipeline.
The Arun reservoir is a compositionally dynamic system. With pressure depletion, the water content of the reservoir gas increases significantly due to water vaporization under the high temperature conditions. Secondly, retrograde condensation and condensate revaporization effects impact compositional performance.
Furthermore, injection of lean gas changes the fluid composition within the reservoir and reduces dew point pressure and hydrocarbon yields. Dissolution of hydrocarbons and carbon dioxide from both connate water and the aquifer also contribute to compositional changes. To properly fully compositional model was employed to simulate the field.
Yassin, A.A.M., U. Teknologi Malaysia (Malaysia)
Whilst the incremental oil potentially recoverable by the application of enhanced oil recovery (EOR) processes can only be reliably estimated by a detailed study of each reservoir, in order to provide an early guide to the scope for EOR in Malaysia, a preliminary survey has been carried out. The approach in this preliminary survey was to develop a set of screening criteria for the various processes being developed and to use these criteria to identify possible candidate reservoirs. The potential for incremental oil recovery was then determined by applying factors obtained from the assessment studies referred to above or from published sources.
The review of EOR potential within Malaysia has suggested that only a small number of reservoirs are unsuitable for EOR and there is substantial scope for increasing the yield from known light oil and gas condensate reservoirs. The possible contribution that could be made by individual processes is fairly evenly distributed between polymer floods, surfactants, carbon dioxide and nitrogen or hydrocarbon gas.
The enforcement of strict conservation measures and depletion control had change the development strategy by integrating EOR into conventional method of production with an early implementation of EOR in order to maintain the viability of EOR projects.
What is Enhanced Oil Recovery or (EOR)? EOR implies oil recovery beyond the conventional recovery stages of primary or secondary recovery which include natural drive, waterflood and gas injection. When the EOR is implemented depends on the characteristics of the oil; for light oils, EOR refer to techniques after primary and secondary recovery which include surfactant flood, polymer floods, miscible drive and even thermal methods and for heavy oils, EOR imply to technique after primary recovery which include steam injection and in-situ combustion. So EOR is to recover more oil after conventional recovery stages.
As a starting point in considering EOR in Malaysia fields, it is important to examine existing primary/secondary recovery and determine an early initiation programme before the field reached an advanced stages of depletion by primary/secondary production. EOR need to be undertaken while the existing wells and surface equipment are still intact and useable. Very few prospects are expected to be profitable that economics will permit redrilling of wells and replacement of surface equipment since oil recoveries are expected to be substantially lower than that of primary/secondary method. Most EOR methods are heavily front-end loaded with chemical and/or equipment so timing of EOR projects is very important for it to be economical feasible.
In this paper, we shall discuss the need of EOR, the current EOR technology and the potential of EOR in the context of Malaysia.
Before understanding the purpose of EOR, it is necessary to examine the recovery efficiency by primary/secondary method. The fraction of oil recovered by secondary/primary method depends on the following factors:
a) areal sweep efficiency b) displacement efficiency c) contact factor
Huffco Indonesia has developed and installed a computerized database system called PARM System - Production and Reserves Monitoring System. This integrated database handles data that includes reservoir, geological, production, operations and mechanical well data. while the PARM System data are acquired and controlled from many technical and operations disciplines within the it is always input as close to the original source as possible.
The PARM System, as an integrated production and reserves data source for Huffco Indonesia, has applications across a wide range of engineering and operations disciplines. Daily production and operations reports, monthly production allocation and product distribution reports, daily drilling reports and summary reports and many other necessary routine reports are. generated by the PARM System. Benefits of analysis of large volumes of data, which were previously very cumbersome to attempt, are now being realized by engineering groups. Ad-hoc data retrievals provide consistent current and historical data for production and reservoir engineering applications.
An integrated computerized database system such as the PARM System, provides a cost and time efficient engineering and operations tool. It provides unparalleled accessibility to any data likely to affect or resulting from the oil and gas production of a well, zone or field. Accuracy of original data is improved due to multi-user review and built-in integrity chocks. Development of a system, such as the PARM System, should be done on a prototype basis under direct engineering management.
Application of computer technology to the petroleum industry is manifested in the PARM System by virtue of capturing and handling of the basic oil and gas operations and engineering data. This paper describes the design and implementation concepts of the PARM System as well as engineering and operations applications ranging from simple reports and data retrievals to interfacing with reservoir simulation software.
Huffco Indonesia is the operator of an oil and gas Production Sharing Contract (PSC) area in East Kalimantan, Indonesia.
Wells in the PSC area currently range to 15,000 feet in depth with producing horizons being completed in various intervals between 1000 feet to 12000 feet. In one of the four currently producing fields, Badak, there are more 200 unique zones. Producing and producing fields have a total of 336 wells. Many of the wells in the producing fields have dual or multiple completions with some having commingled zone production. while the four currently producing fields produce approximately 37000 barrels of oil and condensate per day, the major production is natural gas where the capability is in excess of 1 billion standard cubic feet per day. The natural gas production, after processing at the respective fields, is supplied to the Bontang LNG plant where it is liquefied and utilized to fulfill contracts with offshore buyers. With firm long-term contracts in effect, it is imperative that the supply be able to meet the demand. To insure that this criterion is maintained it is essential to have an accurate, current, accessible database of the various parameters affecting the ability to supply.
Huffco, with consulting assistance, performed project definition and planning study which aided in defining objectives and the philosophy of operation of a Production and Reserves monitoring System.
In assessing the large volume of interrelated data to be handled the objectives of Production and Reserves Monitoring System were defined to be as follows:
- Provide timely common access to basic data for performance monitoring. Under the existing system considerable time could pass before basic data such as well tests, would reach personnel responsible for monitoring and analysing well performance.
- Minimize redundancy of information handling, transcribing, summarizing and copying of data resulting in time loss and frequent data transcribing errors.
Completion operations, for oil and gas wells, are usually performed in casing sizes not exceeding 13-3/8" (34.0 cm) with the majority of completions being performed in 9-5/8" (24.5 cm) and smaller. As such, the availability of completion equipment, for large diameter casings, becomes extremely limited or nonexistent, Occasionally, conditions may exist which require the completion to be designed in a casing size larger than 13-3/8" (34.0 cm). In order to complete in these casing sizes, special equipment must be designed.
This paper discusses the design criteria, development, and subsequent use of perforating and gravel pack equipment generated for use in 20" (50.8 cm) casing. The theoretical approach to the evolution of this equipment is applicable to the development of additional systems.
While completion equipment is largely designed for 9-5/8" (24.5 cm) casing sizes and smaller, with some equipment available up to 13-3/8" (34.0 cm), perforating and gravel pack equipment is virtually nonexistent in sizes greater than 9-5/8" (24.5 cm). Due to specific well completion requirements it may be advantageous to be able to complete in the larger diameter casing sizes. With equipment being unavailable for these larger sizes, special equipment must be developed.
The herein discussed completion system has been specifically developed for 20" (50.8 cm), 133 lb/ft (198 kg/m) casing. In this application a very shallow, low pressure, gas zone exists beneath a platform. It is the operator's intent to set 20" (50.8 cm) casing across the zone and attempt to blow down the gas. Following depletion of the zone, the 20" (50.8 cm) wellbores can be cleaned out and deepened to the primary objective zones. Further development drilling could then commence with less risk and lover costs.
With the primary objective of the project being the depletion of the reservoir, the resultant completion had to be installed in the most efficient manner possible. Owing to the less than 500 psi (3447.5 kPa) static reservoir pressure and the desire to deplete as quickly as possible, the perforating system had to deliver the highest shot density possible with the greatest amount of charge performance. This would provide for the maximum flow rate by minimizing pressure loss through the completion. A systems analysis plot, Fig. 1, supports this and, thus, fostered the need of a specialized perforating gun.
Existing perforating equipment would have required multiple trips to achieve the desired perforation shot density, and would not have been able to offer positive, shot orientation. Performance would also suffer as clearance between the gun outside diameter and the casing inside diameter would have been difficult to control.
Consequently, a perforating system was needed that would offer a very high shot density with maximum performance, while affording positive shot orientation.
Due to the zone being gas, positive well fluid isolation and pressure containment became a criteria. This precluded the use of existing large diameter equipment, which typically have lead seals that are not capable of effecting a suitable gas seal. Additionally, the original design parameters called for the use of a retrievable seal bore packer as the perforating packer.
With the expressed desire to underbalance perforate, the requirement for positive gas pressure containment, and the need for secure casing anchorage, a special packer and associated gravel pack assembly was essential.