bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Water Base Spacer with Thixotropic Cement Systems Improves Cement Jobs
Authors: Crinklemeyer O.W. , Puntney A.W. , Sharpe James R.
Published: December 2007

Cementing has been improved by application of a new water-base spacer ahead of thixotropic cement systems. Weight differential between the spacer and drilling mud can be easily controlled to provide good mud removal. The spacer helps control water loss of the following cement thus permitting use of a thixotropic system with expansive and proper rheological properties. Both bond logs proper rheological properties. Both bond logs and stimulation results have confirmed better cementing jobs using this new cementing technique.

Introduction

Past field Experience and laboratory studies have led to the identification of several factors which contribute to better cement jobs. Some of these factors are: use of a spacer to separate mud and cement, use of a low fluid loss cement system, and use of a cement that expands. In many areas, it has also been found desirable to use a thixotropic cement.

In the past it has seldom been possible to make use of all these factors in a single application. For example, known fluid loss additives could not be used with thixotropic cements since they dispersed the systems. Repeated failure to find a fluid loss additive for the thixotropic systems led to a new approach to this problem. It was decided to develop a spacer which would lay down a filter cake to control the fluid loss of the cement that followed it. In addition to providing fluid loss control for the cement, such a spacer would have to meet other requirements. Some of these are:It should be compatible with drilling muds.It should be compatible with the cement systems.It should have low fluid loss.It should be a water-base material, rather than oil, to facilitate disposal.

Such a spacer has been developed. For the purpose of simplicity, it will be referred to purpose of simplicity, it will be referred to as WBS (water-base spacer) in this paper.

WATER BASE SPACER

The water-base spacer consists of gelling agents and fluid loss additives. Actual development, however, required extensive research. The most difficult phase was finding the proper fluid loss additive.
Stimulation Evaluation by Type Curves: Case Histories
Authors: Sinha B.K. , Pugh T.D.
Published: December 2007

The purpose of this paper is to show the practical usefulness of Ramey et al. type curves in evaluating the results from stimulation treatments. This in turn aids in designing more effective stimulation treatments. Several case histories from different areas are included for illustration.

Introduction

A large number of wells now being drilled and completed are in reservoirs which would have been classified as uneconomical a few years ago. These low permeability reservoirs (less than 1 md) permeability reservoirs (less than 1 md) normally do not produce hydrocarbons economically without some type of stimulation treatment. Large size stimulation treatments (hydraulic fracturing and/or acidization) are increasingly becoming an integral part of well completion practices. In many cases, the production from these wells is too small to measure prior to the stimulation treatment, however, the same wells produce at economical rates after the stimulation treatment. Therefore, it is important that stimulation treatments for these low permeability reservoirs be carefully designed.

Traditionally, transient pressure tests have been used for determining the condition of a well prior to a stimulation treatment. The same type of tests may be applied in evaluating the effectiveness of a stimulation treatment. The application of such tests is discussed briefly in the SPE Monograph, Vol. 2, on Hydraulic Fracturing by Howard and Fast. Details concerning the different types of tests and analysis techniques are covered in SPE Monograph, Vol. 1, by Matthews and Russell. This monograph (Vol. 1) covers the state of the art as it existed prior to 1967.

Since 1967, considerable progress has been made in the field of transient pressure analysis. Most significant has pressure analysis. Most significant has been the improved understanding, of the early time pressure behavior of transient tests, which were considered too complex for analysis and thus were not utilized in the past. This has led to the analysis of the short-time data by type curve matching techniques. Developments in the field of well testing since 1967 have been summarized from a practical point of view by Ramey.
Foamed Acid As A Means For Providing Extended Retardation
Authors: Holcomb David L.
Published: December 2007

Foamed fluids with nitrogen percentages or qualities greater than 60 percent have been used to provide greater efficiency in fracturing fluid design than other conventional types of frac fluids. When acid rather than water is used for 15–40% of the fluid volume, the fluid retains the same efficiency characteristics of a stable foam with one additional dimension. The added dimension is that the acid will remain virtually unreacted while being pumped into even the most soluble formations, and only begins to react when its leak-off/reaction controlling movement is stopped. It is suspected that bubble configuration and structure play an important role in preventing reaction to any great degree before the fluid ceases to be pumped. However, to place the acid a given distance into the formation, with conventional foam qualities or gas percentages requires fracturing rates and pressures which limit application of such a retardation system in many reservoirs where concern for break-through via fracturing into water-bearing zones exists. Therefore, this technique is possibly limited to fracture acidization, but testing is presented to show the effects of acidization of soluble cores with lower quality foam (25%-50% N2 gas). Actual job results are presented with foamed acid in the lower quality ranges.

Introduction

The use of stable foam stimulation has been well documented in the literature in recent years. Its use has been in the realm of stimulation via fracturing and proppant placement. Blauer, Mitchell, Kohlhaas et. al., have described the mechanisms of foam rheology and efficiency within the realm of high quality or low quality foams (those with high gas volume to total foam volume ratios). Others have suggested foam properties in porous media. The ranges with the prescribed efficiencies for fracturing include those qualities between 0.5236 and 0.95 theoretically, and practically, those between 0.65 and 0.85. Low fluid loss with spurt losses approaching zero, and CI values of 1 × 10(-4) are the known benefits with foamed fracturing systems. Actual field demonstrations and laboratory demonstration of this efficiency were the first steps in the establishing of a mechanism for the extended control of HC1 acid reaction on soluble formations. Thus extended penetration of "live" HCl further away from the immediate well bore can be realized. Retardation of acids by a variety of means has been extensively investigated.
Polymer Use in Calcareous Formations
Authors: Townsend Wayne R. , Becker Steven A.
Published: December 2007

The use of polymers to improve areal and volumetric sweep efficiency of waterfloods in limestone and dolomite reservoirs has been very limited and has seldom achieved the desired results. Anhydrous polymers, used in calcareous formations, have been generally ineffective. A relatively new process has been developed and field tested whereby a monomer solution is mixed and pumped into the formation. Once in place, the well is shut in and the monomer allowed to polymerize in situ. The resultant polymer may polymerize in situ. The resultant polymer may (within limits) vary in concentration and viscosity as desired.

Successful treatments have been performed in carbonate reservoirs in three areas of West Texas and New Mexico, and results have been evaluated and studied over several months. Laboratory work has been done on actual formation rock to determine adsorption characteristics and length of time retained.

Introduction

Various type treatments have been used in injection wells in an attempt to increase the volumetric and areal sweep efficiency of waterfloods in limestone and dolomite reservoirs. Polymers, slurries, and gelatinous Polymers, slurries, and gelatinous materials are just a few of the more common agents used in this application.

Polymers used to increase the viscosity of the injection water may improve the areal sweep efficiency by producing additional oil from streamlines that have been developed between the injection and production wells.

Craig defines areal sweep efficiency as follows.

"In water-flooding, water is injected into some wells and produced from other wells. In an areal sense, injection and production take place at points. As a result, pressure distributions and corresponding streamlines are developed between injection and production wells. In symmetrical well patterns, a straight line connecting the injector and producer is the shortest streamline producer is the shortest streamline between these two wells, and as a result, the pressure gradient along this line is the highest. So injected water moving areally along this shortest streamline reaches the producing well before the water moving along any other streamline.
Denver Unit 10-Acre Infill Pilot Test and Residual Oil Testing
Authors: Maguson W.L. , Knowles J.D.
Published: December 2007

Engineers, Inc.

A 10-acre infill pilot test was conducted in the Denver Unit of the Wasson San Andres Field of West Texas to determine if the Unit could be further infilled economically to a tighter spacing at the culmination of a 20-acre infill program. Primary objectives of the test were to (a) delineate pay discontinuity in this San Andres dolomite reservoir, (b) determine size, shape, and orientation of waterflood fronts, (c) determine oil productivity of potential 10-acre locations, and productivity of potential 10-acre locations, and (d) evaluate remaining oil saturation.

From the results of the three-well program, it was concluded that the pay program, it was concluded that the pay continuity is higher than had been interpreted from previous work. All productive zones within the pay interval are being flooded, although at different rates such that 10-acre locations do not appear to have sufficient economic potential to support further infilling. From test data, a preferential directional conductivity could not be ascertained. The results of several methods of investigating residual oil saturation (well bore logs, whole core analysis, laboratory core centrifuge, counter current imbibition tests, and laboratory waterflood susceptibility tests) are discussed.

Introduction

A previous paper has discussed the changing concepts in the Denver Unit carbonate waterflooding with respect to geology, reservoir engineering, injection and production, and development (20-acre infill drilling). Subsequently, a 10-acre infill pilot test was carried out to determine if the Unit could be further infilled economically at the culmination of the 20-acre infill program. Primary objectives of the test were to (a) delineate Primary objectives of the test were to (a) delineate pay continuity at closer well spacing, (b) pay continuity at closer well spacing, (b) determine size, shape and orientation of waterflood fronts, (c) determine oil productivity of potential 10-acre locations, and productivity of potential 10-acre locations, and (d) evaluate remaining oil saturation to waterflooding.
Improving Reservoir Management for a Mature Field by Reservoir Characterization
Authors: Naguib M. A. , Hussein A. , Rial R. M.
Published: December 2007

Ras Budran filed is a massive Nubian sandstone reservoir compartmentalized by major faults acting as partial barriers. Vertical communication is impeded by hydraulically sealing shale layers in the development of three main pressure regimes. The pressure is supported by a combined water injection and aquifer drive. Pre-mature water breakthrough has been observed in the middle of oil leg, which in turn limits the corrective action of the isolation of the watered out zones.

A detailed reservoir characterization and engineering study was implemented with the objective of improving the vertical definitions in the reservoir. New reservoir sublayers were developed based upon open and cased hole log data in addition to the incorporation of core data.

The history-matched model was then used to confidently check the production well pattern, placement performance and then used to investigate the viability of infill wells to improve drainage pattern and sweep efficiency.

This paper discusses the different phases of the field development and how the reservoir management was optimized with time in order to access the remaining reserves of the field.
Compressibility Factor for Sour Gas Reservoirs
Authors: Elsharkawy Adel M. , Elkamel Ali
Published: December 2007

This paper presents the initial stage of an effort aimed at developing a new correlation to estimate pseudo critical properties for sour gas when the exact composition is not known. Several mixing rules and gas gravity correlations available in the literature are first evaluated and compared. The evaluation is performed on a large database consisting of more than 2000 samples of sour gas compositions collected worldwide. Several evaluation criteria are used including the average absolute deviation (AAD), the standard deviation (SD), the coefficient of correlation, R, and cross plots and error histograms. The mixing rules include: Kay's mixing rule combined with Wichert-Aziz correlation for the presence of non-hydrocarbons, SSBV mixing rule with Wichert and Aziz, Corredor et al. mixing rule, and Piper et al. mixing rule. These methods, in one form or another, use information on gas composition. Three different other methods that are based on gas gravity alone were also analyzed. These are: Standing, Sutton, and Elsharkawy et al. gas gravity correlations. While the methods based on knowledge of composition showed reasonable accuracy, those based on gas gravity alone showed weak accuracy with low correlation coefficients. A new gas gravity correlation that is based on the fraction of non-hydrocarbons present in the sour gas was proposed. Preliminary results indicate that a good improvement over past gravity correlations was achieved. The compositional correlations, still show, however, better accuracy. Research is still going on to come up with more accurate correlations that are based on only readily available descriptors.
New Well Architecture Successfully Optimizes the Development of Fluvio-Deltaic Multi-Layered Gas Field
Authors: Dyer George R. , Ismanto Bambang , Haas Mike
Published: December 2007

VICO Indonesia operates the Sanga-Sanga Block in Indonesia as a Production Sharing Contractor to PERTAMINA, the Indonesian National Oil Company. The Sanga-Sanga Block is located in East Kalimantan near the city of Balikpapan and consists of four major fields producing approximately 1.3 BCFD of gas and 50,000 BLPD. The processed gas is delivered into a pipeline system that carries the gas to the Bontang liquefaction plant. The gas is converted to LNG for distribution and sales throughout the Asia Pacific Rim.

The main geological depositional system is fluvio-deltaic. Nilam and Badak, the two largest fields, contain numerous stacked pay intervals that can total up to 1,000 net feet of pay in 50 separate reservoirs that are distributed over as much as 7,000 vertical feet. The reservoirs are in a sand/shale sequence deposited in a channel sand and point bar environment. There are some oil accumulations, but the majority of the reservoirs are gas. There are a few large reservoirs in the hundreds of BCF range, but most are smaller reservoirs, less than 20 BCF.

For over twenty years, VICO Indonesia drilled and completed "conventional" gas wells that included dual tubing strings and multiple packers. The large number of individual reservoirs and their small size makes dedicating a well to a single reservoir impractical. Numerous workovers are required with this type of geology and the dual completions are complicated and expensive. As the fields age, the number and cost of the workovers continuously increase. Because of the mechanical limitations in dual tubing string completions, the options for stimulation are limited and the potential for formation damage during workover operations is substantial.

In 1996, a multi disciplinary team was formed to evaluate the benefits and risks of various new well architectures for future Nilam Field development. The study concluded that a monobore or tubingless completion was the best option. The 4-1/2" monobore completion eliminates all packers, nipples and sliding sleeves and is especially appropriate for gas production because water handling and artificial lift is usually not required. This new well architecture has been implemented and successfully reduces drilling and completion cost by 20%. It also allows significant improvement in completion techniques, eliminates rig workovers, increases reserve recovery per well, and reduces the number of future drilling wells. The tubingless completion also allows better reservoir evaluation and selective zone stimulation or isolation. This paper will review the monobore evaluation process, benefits, and results to date.
Computerized Sucker Rod Pumping Evaluation
Authors: Cochran P.F. , Miller L.N. , Threewit C.R.
Published: December 2007

Publication Rights Reserved

This paper is to be presented at the 38th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in New Orleans, La., on October 6–9, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of the JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

A computer program has been developed which utilizes readily available information to calculate (1) the dynamic forces in a sucker rod pumping system, (2) the efficiency with which the installed equipment is operating, and (3) the actual cost of operation of the installed equipment and the cost of any inefficiency with which the equipment is operating.

The print-out contains all the information necessary for comparison of actual and ideal operating conditions. Experience to date indicates that 20 to 60 percent of the cost of operating sucker rod pumping systems is the result of inefficient use of pumping equipments

Introduction

The goal of any producing operation is to recover the maximum oil at the minimum expense consistent with good operating practice. During the past several years, The Pure Oil Company has been increasing its concentration on this philosophy. An analysis of operating costs almost invariably resulted in the conclusion that something needed to be done about pumping costs. Not only were milling systems operating at low efficiencies but, in addition., it appeared that considerable money was being spent for oversized equipment.

A well by well study and analysis of pumping systems did not appear feasible because (1) dynamometer analyses require far more time than Pare's technical staff could devote to the problem and (2) manual calculation methods are time consuming and not sufficiently accurate to yield worthwhile results.

During early 1962, Midwest Research Institute, under contract to Sucker Rod Pumping Research, Incorporated completed the development of a method of calculating the dynamic forces in a sucker rod pumping system. The method requires only input data which are readily available and, as Pare's field tests have proven, yields results which compare very well with measured values. The major exception to the good comparison is in calculated torque, which ranges up to 60 percent above the measured torque.
Use of High-Strength Proppant for Fracturing Deep Wells
Authors: Cooke Claude E. , Gidley John L. , Mutti Dean H.
Published: December 2007

A new fracturing process using a high strength bauxite as the proppant has been developed which generates long-lasting, high conductivity fractures in deep, hard, high stress formations. No unusual difficulties have been experienced in handling and pumping the proppant. Good production increases have been obtained in most of the wells treated with the new process.

The process is particularly applicable to deep reservoirs. Detailed economic analyses, made with a reservoir simulator and using reservoir and economic parameters for a deep, tight, East Texas area gas well, show that large economic benefits can be expected from use of the process.

Introduction

The use of high-strength bauxite as the proppant in hydraulic fracturing was reported proppant in hydraulic fracturing was reported at the Fall Meeting of SPE in 1976. The purposes of this paper are to give an updated purposes of this paper are to give an updated report on usage of the material in Exxon USA wells and to discuss an economic analysis that can be used to evaluate the usage of an improved propping material. propping material. Many deep wells will require hydraulic fracturing treatments in order to produce at economic rates. Other wells can be greatly improved economically by a successful hydraulic fracturing treatment. To achieve successful fracturing results, a material having properties superior to sand is needed to prop open the hydraulic fractures created at the high earth stresses present in deep wells. Silica sand, the commonly used propping material, tends to crush in closure stresses encountered in deep formations, producing fine particles or fragments that can drastically reduce fluid conductivity of the propped fracture. This crushing of the sand leads to lower productivity of the well.

The problem of finding a proppant material that will withstand high stress without excessive crushing has been the subject of research in the oil industry for a number of years. Exxon Production Research Company (EPR) worked for several years on this problem. A wide variety of materials were tested in the laboratory, following the development of equipment suitable for simulating reservoir conditions.
Assessing the Capabilities of a Cased-Hole Reservoir Analysis System in the Gulf of Thailand
Authors: Odom Richard C. , Platt Christopher J. , Pavlakos Paul
Published: December 2007

The option of using a cased-reservoir analysis system as an alternative to traditional open-hole log analysis was tested as a method to reduce drilling rig time. On a series of five wells in the Gulf of Thailand, an integrated pulsed-neutron system that measures Sigma, inelastic spectroscopy, neutron porosity and density was used to drive the cased-hole analysis. The capabilities and accuracy of the cased-hole results were compared to open-hole porosities and water saturations.

One concern for cased-hole logging is accuracy in this well-completion environment. These wells are completed as monobores with 2⅞-inch tubing cemented directly into the 6⅛-inch open hole (no well casing). Initially, the pulsed-neutron porosity coefficients for 5½-inch casing were used with reasonable accuracy. To increase the porosity accuracy, the data from this test served as input to an artificial neural network for determining porosity coefficients in this specific borehole environment.

The project consisted of 12,099 feet of log data including 30 gas sands, 5 oil sands, and numerous water sands in the five wells. The results of this assessment are shown via log examples over specific intervals. In addition, several cross-plots comparing open-hole data to cased-holed data show the results of this evaluation. Graphs of net pay, net effective porosity, net shale volume, and water saturation are shown for the entire project.
Sand Control Screen Plugging and Cleanup
Authors: Asadi Mahmoud , Penny Glenn S.
Published: December 2007

Sereens are used to mechanically restrain formation solid entrance to a wellbore. As effective as this process may be, in many cases it fails to retain solids. This is due to screen plugging either during screen run in a wellbore or during production where larger size particles bridge against a screen and finer size particles plug the screen. In either case, plugged screens are subjected to a cleanup treatment. In this paper, a series of large-scale tests are conducted to evaluate screen cleanup methods such as acid spotting, use of enzyme and acid activated-breaker, backflow, and a combination of these methods under downhole conditions. At first, each screen's retention performance is evaluated. Then, a drill-in-fluid containing solids is pumped into a large-scale flow-cell at a constant pressure drop across the screen to simulate a screen run down in a wellbore. Inlet and outlet samples are collected to evaluate removal efficiency of each screen. Then, each plugged screen is subjected to a cleanup method. The effectiveness of each cleanup technique is evaluated based on the retained permeability of each screen. Degree of plugging and percent area open to flow for each screen is also presented.
The Future of Partnering and Alliancing
Authors: Elshahawi H. , Sengul M.
Published: December 2007

Since its birth, the oil and gas Industry has been faced by sudden and brutal variations in its economics. The recent shock that occurred in the late 90's has forced the entire industry into major restructuring, including consolidations and mergers. The major initiative to define and implement new business relationships between oil and gas producers and service suppliers had already begun in the early nineties and had been driven by oil company strategic thinking in the relatively stable yet uncertain environment that prevailed earlier to that last shock. Moreover, deliberate restructuring has been taking place within many oil companies throughout the decade, and innovative technology was being introduced by the service industry at an unprecedented rate. Key developments such as 3D seismic, horizontal drilling, geosteering, coiled tubing applications, improved stimulation methods and advanced wireline logging technology have made many challenges of the past realities of the present. Additionally, the information technology revolution has created virtual teams by linking experts and data sources worldwide.

In reaction to restructuring, innovative technology, and the uncertain future of the market, there has been an increasing trend in the petroleum industry to establish strategic partnerships. Such partnerships represent a departure from the conventional oil company philosophy that relied on internal administrative controls. This paper investigates the benefits of partnerships to both oil and service companies. Industry perceptions of partnerships and past performance are discussed, the future of alliancing is explored, and a formula for successful partnering is proposed.
Legendre: A Team Effort Makes a Small Offshore Development Economically Viable
Authors: Clegg Duncan , Guerrera Lupo , Kirk-Burnnand Baden , Steenson Bruce
Published: December 2007

The Legendre North and Legendre South fields lie in 50m water depth in Production License WA-20-L, some 100km north of Dampier West Australia. The Legendre North field was discovered in 1968, but appeared uneconomic until further drilling, following the acquisition and interpretation of 3D seismic, augmented the resource base by extending the northern field and discovering Legendre South in 1997/1998. Subsequent geoscience and engineering studies have shown that the development of the 44 MMbbl oil reserves at the probable level is feasible, but is nevertheless still not without risk in this challenging metocean and geotechnical location. A cooperative effort between the Joint Venture participants coupled with somewhat novel facilities concept and contracting has however made it viable.

The two fields will be developed via four production wells producing to a single Mobile Offshore Production Unit (MOPU), converted from an existing jack-up drilling rig. Oil will be exported from the production facility via a 2.5km pipeline to a tanker moored to a Catenary Anchored Leg Mooring (CALM) buoy. Excess associated gas will be reinjected via a dedicated injection well. The MOPU is to be provided under a Service Agreement through which the contractor will receive a daily fee for processing the Legendre production, reinjecting excess associated gas and exporting the crude oil product to the tanker on the buoy.

Woodside Energy Ltd. is operator of the Licence with JVP's Apache Northwest Pty Ltd. and Santos Limited. The project is being managed by a small integrated team which, through its membership, combines the best of both Woodside and Apache expertise and management styles.

This paper provides an overview of the development concept, the integrated project management structure and the contracting strategy, which seeks to align the business objectives of the Joint Venture and the main contractor for the benefit of all involved in the project.
A Method to Estimate the Drainage Area of a Horizontal Well
Authors: Permadi P. , Putra E. , Butarbutar M. E.
Published: December 2007

Evaluation of the production performance of a horizontal well is an effort to justify both the technical and economie successes of the project, particularly in an area of horizontal well development. When this implementation shows a good promise for the plan of reservoir management, the engineers involved should be able to estimate the drainage area of the horizontal well. This is of importance in optimizing well spacing for the development.

This paper presents a method to estimate the drainage area of a producing horizontal well. The method was developed by combining an equation of production decline introduced by Shirman (1998) with an equation of material balance. The advantages of the method presented here over the existing ones available in the literature are simple and no requirement of ultimate recovery data.

Field data of four producing horizontal wells were used to evaluate the proposed method. Having the production performance and the rock and fluids properties data, calculation was performed to determine the drainage area of each well under the study. The validation was done by (1) comparing our results with that of a previous study and (2) calculating the productivity index (PI) using a horizontal well inflow equation and then compared with that measured in the field. The comparisons show a very good agreement for all the cases considered, revealing that the method is successfully applied.

In addition, the paper also discusses the strategy of orienting a horizontal wellbore to maximize the benefit of horizontal well application.
Stag Development - Challenges and Successes in the First Two Years
Authors: Goodacre J. , Ion A. M. , Alexander I. R. , Aitken K. J.
Published: December 2007

Stag oilfield commenced production in May of 1998 and reached peak rates in excess of 30,000 barrels of oil per day in July 2000.

Stag development is an $A200 million oil development on the Northwest Shelf of Western Australia (Fig 1) designed to produce in excess of 50 million barrels of oil over the life of the field. The field was discovered in mid-1993, delineated in 1994 to 1996, and tested with a horizontal well production test in 1996. The development consists of a Central Production Facility containing wells and processing equipment, a 2km subsea line to a CALM buoy and FSO storage and export tanker. Designed to have five producers and three water injectors producing around 30,000bopd oil, the field did not meet initial expectations. Gas-oil ratios were higher than forecast, peaking in excess of 1000scf/bbl and causing significant operating problems for the process plant and electrical submersible pumps. Oil production was lower in the east of the field than anticipated, due to the thinning or absence of high productivity sand units, reservoir pressure support was poorer than modelled leading to more rapid pressure decline than anticipated, and one well produced significant quantities of sand and clayey solids. These challenges led to a significant re-work of the development. Subsea water injectors were added, wells were recompleted in better quality reservoir, pump designs were significantly changed, the reservoir model was rebuilt and more producers were added (Fig 2).

At year-end 1999, Stag came of age - production reached design basis levels, reliability approached 100% and overall reservoir performance met expectations.

The paper reviews three key elements of the development - Reservoir Description and Performance, Completion Design and, Facility Design and Performance - and presents the lessons learned.
Characteristics of Fractured Reservoirs in Magmatic Rocks and Their Reservoir Properties
Authors: Koshlyak V. A. , Dong T. L. , Hai P. D.
Published: December 2007

Oil in magmatic rocks has been known for a long time, however exploration for it has been conducted relatively weakly. In the meantime, proceeding from the concepts of plate tectonics, geodynamics of rock deformation, the significance of the rocks in oil accumulation increases and they have high hydrocarbon potential confirmed by a number of discoveries in the last years.

The reasons for the careful approach to the type of reservior rocks are: 1. very complex porous patterns, and the processes leading to generating reservoir properties, time of the generation and reservoir property distribution in area and in sequence are not clear; 2. the problem of searching appropriate geophysical methods to delineate fractured zones has not been resolved; 3. no log interpretation methodogy has been worked out, and; 4. the drilling, testing and stimulating technologies for the basement rocks ocurring at deep depths are not suitable. The genesis of the oil, its migration and accumulation in the basement reservoir is also not clear. The published articles deal with fields in the kind of the rocks are limited and they mainly described the geology of the fields.

To resolve the mentioned above problems, all geological and production data of well studied fields in the world should be carefully learned and analyzed in order to built a appropriate reservoir rock model for each of them. In this sence White Tiger oilfield - a unique large off-shore field in South Vietnam - serves as one of the models of magmatic reservoir rocks.
Application of One-Trip Multi-Zone Gravel Pack to Maximize Completion Efficiency
Authors: Vickery E. Harold , Bayne Christian F. , White William G. , Liu Liang Yue , Yue Jiang He , Chen Bi , Wu Cheng Hao
Published: December 2007

This paper uses case histories from several 3- and 4-zone gravel packed wells in The Peoples Republic of China's Jinzhou 9-3 (JZ9-3) Bohai Bay field to address the potential of one-trip multi-zone gravel packing. Objectives included improvement of economic margins in development wells by maximizing efficiency and reducing rig time for completion operations. The paper describes the operational and reservoir parameters that led to successful application of this technique during development of the JZ9-3 field. Based on this study, the authors provide guidelines for application of the technology to other reservoirs and compare rig times with those of more conventional methods currently used to complete multi-zone wells.

The scope of the project did allow for some optimizations to be made both in operations and in design of the system. These enhancements resulted in a system that can be used for zones of varying length. The system also allows gravel placement across each individual zone to be performed either below or above fracture pressure, while maintaining total pressure isolation from all other zones.

Data are presented that show the actual average time saved in excess of 50 percent for 4-zone gravel packed wells.
Technology Advancements in Optimum Wellbore Placement
Authors: Md Zin Che' Lah , Sering Lancelot , Kamarrudin Sazli , Good Alan , Gjerdingen Tore
Published: December 2007

Advances in drilling technology are now making possible the drilling and completion of oil and gas wells thatjust a few years ago would have been inconceivable. Significant advances in downhole tool sensor placement and reliability are aiding operators in optimizing wellbore placement to within a matter of tens of centimetres in the vertical plane. Over and above this lateral well placement in the 3D horizontal plane now make it possible to intersect high permeabily horizons and steer the wellpath in three dimensions to ensure the well is able to maintain its position within the "sweetest zone"

In this paper the authors will demonstrate how advanced technology was used to drill the Sotong 5, 6 and 7 trilateral wells using a rotary closed loop drilling system. These types of tools provide enhanced drilling-while-steering efficiency and improved hole quality. It comprises a surface to downhole guidance system, formation evaluation (with optional LWD) and downhole pressure monitoring. These tools can automatically guide the bit to a preprogrammed target and two-way surface communication allows rigsite engineers to adjust the well trajectory to meet drilling objectives and redirect the wellpath based on real-time formation logs, through the utilisation of reservoir navigation services (geosteering). This eliminates the "wait and see" aspect of drilling with conventional steerable systems, which often results in less than optimal well placement, as well as getting continuously updated models of the placement of the drainhole within the reservoir. This technology is augmented through realtime wellsite information transfer from the rigsite to the office. Therefore the critical well path decisions can be made in real time by the team in the office and implemented at the wellsite instantaneously. The paper will discuss tangible performance metrics and attempt to quantify through statistical analysis the added value of such systems.
Innovations in Subsea Development & Operation
Authors: Henry W. C. , Hyden A. M. , Williams S. L.
Published: December 2007

Esso Australia Ltd., on behalf of the Esso/BHP joint venture, recently completed Australia's first deep-water oil and gas development, Blackback, in 395 m water depth in eastern Bass Strait. Esso used a phased development approach and an innovative development concept to mitigate the effect of reserves uncertainty. The development consists of three wells in daisy-chain formation tied back to the existing Mackerel platform, 23 km distant. The development also used innovative approaches for installation of flexible flowline and umbilical jumpers from the drilling rig, management of hydrates in the production flowline and control system integration.

In the same time frame, Esso repaired the failed electro hydraulic control systems of two ten year-old subsea wells. The repair program used an innovative approach to fault diagnosis and field work.
U.S. Drilling - Who, Where, Why and How Deep
Authors: Dougherty Tom
Published: December 2007

1976 was the best year for domestic drilling… in terms of wells completed… since 1964. Improved prices for both oil and gas, despite government controls of both, are reflected in increased drilling during the period 1973–1976. period 1973–1976.Most areas of the country have shared increased activity. The most sizable increase has been in development drilling, followed by close-in exploratory work. Unfortunately, the last two years have brought slight declines in new field wildcats. However, percentage of wildcat success has not dropped.

Production, although still declining, has responded, to a significant degree, to increased activity.

The majority of the nation's drilling is done on an operator-of-record basis, by operators not generally classified as "majors".

Heaviest drilling has tended to appear in areas where gas can be sold to intrastate markets, and in areas where large numbers of oil wells can be completed rapidly, even though the resulting wells would probably have been considered uneconomic at prevailing prices of a few years ago. prices of a few years ago. Average total depths have tended to increase during the past three years, although there has been no marked increase in the number of ultra deep wells.

These, and other characteristics of 1976 drilling activity, with special attention to the Permian Basin, are pointed out in "overview" fashion.

TEXT

The United States became aware, nearly four years ago, of a condition which was well-known to the petroleum industry long before then. There was, and still is, a crisis of energy supply.

The reasons are widely known, but not widely acknowledged. In fact, to this day, the existence of a real problem is not by any means fully acknowledged.

During the period since the 1973 embargo, we have fumbled and faltered our way through charges and counter charges without development of any effective course of action. As a country we still do not have concensus as to what, if anything, should be done, or if anything should be done. One philosophy which has repeatedly been stated, or at least inferred, is that we can do little that's worthwhile in domestic development of conventional energy supplies.
Review of Artificial Lift in Egypt
Authors: Naguib M. A. , Shaheen S. E. , Bayoumi A. El-Wahab , El-Emam N. A.
Published: December 2007

One of the real challenges facing the oil industry in Egypt now, is to keep up production and maximize reserves especially in mature oil fields. The application of artificial lift systems to improve the productivity, whilst ensuring the most effective use of the existing reserves, should optimize the petroleum resources.

A total of 137 oil and gas fields were placed on production since the oil industry in Egypt started in 1910. Currently there are 122 oil and gas fields on stream, among which 9 are gas production fields and the other remaining 113 are producing oil from 1311 oil wells. The natural producing wells are representing 15%, while the gas lifted wells are 24% and the pumped wells are 61%.

This paper presents the philosophy and the methodology of applying artificial lift system in the Egyptian oil fields. Pending on the production forecast and the expected well behavior and also the effects of applying the secondary recovery mechanism either by water flood or gas injection.

Also the problems encountered on well behavior are analyzed and solutions are suggested. Special emphasis is given to the marginal oil fields artificial lifting systems, because of the economical limitation accompanied with such field's development costs.

The concept is not only to equip a well with a cost effective means of artificial lift to be able to continue production, but also to manage the reservoir behavior for the maximum oil recovery.
Mathematical Modelling of Wax Deposition in Crude Oil Pipeline Systems
Authors: Kok Mustafa Versan , Saracoglu Onder
Published: December 2007

Deposition of wax on the wall of the crude oil pipelines is regarded as a problem since the pipeline diameter is reduced. Therefore more power is required to force the same amount of crude oil through the system. In this study, a mathematical model is developed for estimation of wax deposition in crude oil pipeline systems. A computer program was developed to simulate wax deposition phenomena. Each component is characterized by weight fraction, heat of fusion and melting point temperature. Temperature profile along the pipeline, solid-liquid equilibrium constant, wax mole fraction and wax thickness along the pipeline were calculated. This computer program was applied to Kirkuk - Ceyhan crude oil pipeline system. It was observed that wax thickness, after a year, is approximately 0.34 mm and temperature declined from 303 K to around 295 K. The wax mole fraction after a year is approximately 0.2225. The solid-liquid equilibrium constant for the first component was around 0.29 and 355 for the second component after a year.
Successful Optimization and Application of Primary Cement Designs Enables Annular Placement of Casing Perforating Guns for Multiple Zone Completions
Authors: Dillenbeck Robert L. , Cooper Dwayne
Published: December 2007

Recent and exciting technical advances have allowed for the development of a process whereby multiple productive zones in a new well can be identified and set up for external casing perforation and completion in a matter of days instead of weeks. This process uses newly developed tools and perforating guns that are run into the wellbore on the casing exterior prior to the primary cementing of the production casing. Once cemented into the well, the drilling rig can be removed and the well prepared for multiple completions in a single day. However, before any of this can happen, the production casing must be successfully cemented in the wellbore and all productive zones adequately isolated from other formations exposed to the wellbore. Since the annular configuration of the primary casing strings using this new technology is considerably different from a more "conventional" production casing string, they cannot be cemented in the same manner. Due to the unique design of much of the external casing equipment used in this process, many tough cement design and operational challenges had to be analyzed and solved before the first field test well could be drilled and cemented.

The authors will detail the various cementing challenges and how they were overcome in the actual field applications of this new technology. Three new wells in widely separated fields will be examined on a case by case basis to illustrate the application of this new technology and the cementing designs, procedures and techniques used to accomplish the necessary zonal isolation. The three wells ranged from having two productive zones to 12 zones, all of which had to be isolated. Finally, the relative success of the cement isolation of the productive zones in each well will be examined.