bluuebunny/crossref_metadata_2025 huggingface dataset:
A New High-Temperature Oil-Based Drilling Fluid
Authors: Mas M. , Tapin T. , Márquez R. , Gabay R. , Negrín Z. , Díaz C. , Bejarano L.
Published: December 2007

This paper presents the laboratory development and a field trial of a novel 100% oil base drilling fluid system. In response to the need for a competitive high temperature inhibitive system, lab testing found an oil soluble polymer that imparts high temperature high pressure fluid loss control in a mud system with stable rheology and low formation damage. The polymeric additive is the basis for the 100% oil system, which also has an application in standard invert emulsion systems. The 100% oil system is designed to use mineral or diesel oil as the base. The attributes of the system include inherent inhibition and lubricity from the base oil, a mud weight range of 7.0–18.0 ppg, minimal formation damage, resistance to contamination and maintenance of the HPHT filtration control and rheology during high temperature high pressure applications. Laboratory testing has shown the fluid is temperature stable to 400 °F with diesel or low toxicity mineral oil as the base.

This system has been field tested on two wells in Eastern Venezuela. One test was a 6,353', 8 ½" directional interval and the other a 1,053', 5 7/8" horizontal section drilled in near balance conditions with the fluid being nitrogenated to achieve the desired ECD. Both wells were drilled successfully and one well is discussed in this report.

This fluid has a wide range of applications evidenced by the documented properties from the lab and the field tests. This paper covers the system formulations, properties, formation damage tests, and the results from the field test.
Design and Application of a Drill-In Fluid System for the Production Interval in Barinas Area
Authors: Martínez Alfonso , Luzardo Juan P.
Published: December 2007

Drilling of the production interval of oil wells in Barinas area has been carried out using oil-based fluids. In most cases the same fluid used in the intermediate hole has been used to drill the pay zone, after processing it with SCE to adjust to the required density for the final interval. This has led to production indexes below expected forecasts. In order to increase productivity in the area, PDVSA-SOUTH requested to put together a plan in which a water-based Drill-In fluid system had to be designed for two exploratory wells in Torunos and Borburata fields. The objective was to drill the production interval through Gobernador and Escandalosa Formations, reducing damage and controlling any wellbore instability problem that might arise from the water-sensitive shale section above the production interval, known as La Morita Formation. In order to meet this requirement, a detailed study about the petrophysic characterization of the reservoir rock and a compatibility study between wellbore fluid and reservoir fluid were performed. Drill cuttings were used for the former, and crude oil and Drill-In fluids were used for the latter. Scanning Electron Microscopy was used for the cuttings analysis, in order to establish the structure, pore geometry and mineralogy of the reservoir and non-reservoir rock. Shale swelling and dispersion tests as well as permeability plugging and filtration tests were also performed. Based on the results, a FLO PRO™ system was designed, choosing the type and concentration of shale inhibition additives to be included. The particle size distribution of the CaCO3 used as bridging agent and weighting material was also selected. Finally, a hydraulic analysis was done to adjust the rheologic properties of the fluid and recommend some operational practices, so as to have a controlled ECD. The fluid design was successful and the expectations were met.
Primary Cementing Optimisation: Well Conditioning Procedure and Foamed Spacer Use
Authors: Degni Carlos D. , Marcinkevicius Carlos R.
Published: December 2007

Since late 1993, in El Tordillo Field, Chubut, Argentina, Tecpetrol S.A. has experienced severe cleaning and loss of circulation problems while drilling and cementing production casing in very depleted zones located from 4265 ft to 6562 ft, El Trébol and Upper Comodoro Rivadavia formations.

The average depth for the wells studied is 9843 ft, the desired cement top for isolating primary and secondary production zones is 4265 ft.

Several drilling fluids and cementing procedures were optimised through the fifty-well drilling program. In spite of this optimisation procedure, random results were experienced while cementing the production casing, either single or two-stage cementing jobs.

In the last thirteen wells a different approach to circulating and cementing the production casing was adopted.

The 7-inch production casing was circulated while running at pre-selected depths. Preflushes for the cementing job were lightened with nitrogen, thus providing a low density, high viscosity foamed spacer in the front of the primary cement job. The foamed spacer was used to improve displacement efficiency in open hole. The results were positive, the low-density spacer and preflushes reduced loss of circulation while cementing the production casing and improving hole cleaning.

So far the thirteen wells were cemented in one stage using foamed spacer and lightened preflushes ahead of normal density cement slurries. Results have been very good with cement columns rising up to 4265 ft. The casing and formation bond for these jobs have been excellent, achieving consistent results and a total saving over 42% of the total cementing costs.
Finite Element Modeling of Heavy Oil Production Using PCP
Authors: Blanco L. B. , Ribeiro P. R.
Published: December 2007

The Progressive Cavity Pumping (PCP) system has become one of the most attractive artificial lift methods used for heavy oil production in land fields. One of the problems associated with PCP is the prediction of the pressure losses in the annular flow between the production tubing and the rod string, which transmits power downhole to the PCP. The irregular annular section due to the rod upsets and the non-Newtonian behavior of some heavy oil initially precludes any analytical approach of the problem, requiring the use of numerical solution. Different heavy oils from onshore and offshore Brazilian fields were rheologically characterized using a strain-controlled rheometer in order to study temperature and elasticity effects on its rheological behavior. For the temperature and strain rate ranges used in the lab, the Power Law model has been chosen to represent the fluid behavior for the numerical simulation of the annular flow field. In order to understand the physical problem, a 2D finite element modeling of the laminar, steady-state, helical flow of a generalized Newtonian fluid was performed, by using Newton's method with an incremental loading scheme. A mixed formulation was applied for the approximation of Navier-Stokes equations and the flow domain was discretized by quadratic quads with linear pressure interpolation. The general conclusions regarding the physical problem are concerned with the rheological behavior of the fluid and with the parameters which mostly influence the pressure losses in the annular flow, during progressive cavity pumping of the heavy oil.
Production Optimization by Combined Artificial Lift Systems and Its Application in Two Colombian Fields
Authors: Borja Hubert , Castano Ricardo
Published: December 2007

The application of combined artificial lift systems yields improved production in terms of costs and rates at better conditions than could be expected from using only one of the individual systems. This new approach overcomes restricting conditions such as tubular size, operating depth, water cut and corrosive gases, while preparing the wells for future condition changes as a result of waterflood/pressure maintenance programs in progress. These combined systems were initially designed for two Colombian oil fields.

The concept considers a primary system such as rod pumping or ESP combined with gas lift as secondary system. The design envelope provides a wide operating range, allowing individual operation of the primary, the secondary and the combined system, reaching the optimal technical and economical performance while the combined system is operating. The operating envelope is framed in terms of production rate and power consumption.

The paper presents the concept of "equivalent depth" (compared to "operating depth"), the design methodology, downhole equipment and field operating conditions and benefits.

The long-term benefits are a reduction in production downtime, decrease in the artificial lift investment by the use of downsized equipment and a reduction in the operational cost due to lower power requirements. Actual field data is presented to corroborate these benefits.
A New Automated History Matching Algorithm improved by Parallel Computing
Authors: Leitão H. C. , Schiozer D. J.
Published: December 2007

Reservoir simulation has become a very common and important tool in the last years due to the great evolution of computers. One of the most important applications in this area is production history matching. Automated history matching techniques were object of several studies in the 1970's and 1980's, but with limited success due to large computational effort required by the usual practical applications. Motivated by recent hardware and software developments, this work presents a new automated history matching technique, which emphasizes the use of parallel computer.

The procedure created in this work searches for a viable practical application which consists of a mathematical minimization of a multidimensional objective-function that represents the differences between observed and simulated data. The matching variables are previously selected by a sensitivity analysis, which can reveal the most important parameters. To minimize the objective-function, two categories of multivariate optimization techniques are investigated and compared: first derivative methods (Gradient and Quasi-Newton) and direct search methods (Polytope and Hooke & Jeeves). It is also presented a more robust hybrid algorithm, which can benefit from the advantages of each of these techniques.

The software PVM (Parallel Virtual Machine) is used to distribute the simulations through the network of workstations and/or to simultaneously obtain multiple solutions, providing an efficient way to accelerate the optimization and/or to overcome local minimum difficulties. Some examples are presented to demonstrate the methodology validity, the benefits of parallel computer and a comparison of the optimization techniques performances.
Use of Reservoir Simulation, Parallel Computing and Optimization Techniques to Accelerate History Matching and Reservoir Management Decisions
Authors: Schiozer D. J.
Published: December 2007

Reservoir simulation is used in several important tasks in the petroleum industry. Most of such tasks require many simulation runs either because there are uncertainties in reservoir characterization and the model has to be calibrated or because many options have to be tested in manual or optimizing procedures.

In the past, computer time was one of the most limiting variables but nowadays computers are becoming less expensive. On the other side, people time is becoming more valuable so they must have tools to make the best use of their minds. Despite of these facts, many important decisions in reservoir engineering are still strongly based on manual procedures even when computers, parallel algorithms and automation tools are available. Furthermore, many companies do not use their network adequately.

In order to contribute to a change in this scenario, this work shows (1) some advantages of building tools using reservoir simulation, parallel computing and optimizing techniques to history matching and reservoir management decisions, and (2) how to make the best use of existing networks and PVM (parallel virtual machine) to accelerate such processes.

A case study using an offshore field is presented to illustrate (1) the advantages of having a computer program to automate some steps of production history matching and (2) the time savings obtained by parallel computing. Some procedures are discussed to obtain the best balance between people and computer time.
The Impact of Front-End Loaded Data Collection on Development Plans for Mahogany Field, Offshore Trinidad
Authors: Lachance D. P. , McCleary N. R. , Jones J. R.
Published: December 2007

New field development planning is a balance of applying known vs. interpreted reservoir data in appropriate levels to the initial field design. Acquiring too little reservoir data before commencing field development can result in either inadequate or over-sized production facilities and/or development dry holes. Neither result is acceptable on a reservoir management or economics basis. For BP Amoco's new Mahogany field development in Trinidad, the project design team created a full field facility design in support of the development plan derived from four exploration wells. As part of a front-end loading design process, the team recommended and drilled two more delineation wells within untested fault blocks of the field. Reservoir information from these two wells completely changed the planned production facilities and production streams from the field. Had the original facilities been built and installed, they would have been in the wrong place and undersized for the production flow streams. Also, the new reserves found by the two wells allowed for the deferral of a second new field development by up to ten years. Commitment of the project team to following and implementing the recommendations of a formal front-end loading process prevented a major mistake.
A Comprehensive Study on Strategy to Improve the Operation and Management of Well Injection System
Authors: Li Haitao , Li Hongjian , Wang Yongqing
Published: December 2007

Keeping injection water well compatible with rocks and fluids in sandstone oil bears is very important for reservoir pressure maintenance during waterflooding. The quality control program of injection water is as being very necessary in protecting formation or preserving the injectivity of wells. In this study, a comprehensive laboratory and field studies were carried out at Rongxingtun oilfield to identify the causes for rapid injectivity decline and to find out remedial treatment methods to improve the water injectivity. Based on analyzing and evaluating damage characteristics of injection water on reservoir core plugs, the new remedial techniques called swelled clay constriction and salinity-gradient-water injection were proposed to prevent the injectivity from declining. The new specifications and quality guarantee system of injection water had also been established. The field test results showed the new salinity-gradient-water injection and swelled clay constriction techniques are effective to improve the well injectivities. Useful classifying criteria according to different characteristics of formations about water quality specifications had been established. A window-based software for operation and management enhancement of water injection system had also been developed.
Mechanical and Thermal Properties of Unconsolidated Sands and Its Applications to the Heavy Oil SAGD Project in the Tia Juana Field, Venezuela
Authors: Vásquez H. A. R. , Sánchez D. M. S. , McLennan J. , Guo Q. , Portillo F , Poquioma W. , Blundun M , Mendoza H.
Published: December 2007

Thermal and mechanical rock properties were evaluated with special laboratory tests and logs to analyze a Steam Assisted Gravity Drainage (SAGD) project by MARAVEN S.A. (now part of PDVSA Exploración y Producción) in the heavy oil Tía Juana field on the eastern side of Lake Maracaibo, Venezuela. This SAGD project is the first application of this technology in Venezuela and consisted of two parallel horizontal wells on top of each other where steam is injected in the upper well and oil is produced in the lower well. Special coring equipment and procedures were utilized in a specific well to obtain a low perturbation core. Dipole sonic logging was successfully used to obtain a continuos profile of P and S wave velocities in these extremely loose unconsolidated sands to serve as calibration with the laboratory tests. A special series of laboratory tests were carried out in this core to determine thermal and mechanical properties which will be useful to characterize these extremely loose unconsolidated sand reservoirs under the varied conditions of temperature and pressure encountered in this project. Basic thermal properties such as thermal conductivity, specific heat and thermal expansion were specifically determined with modern equipment and techniques for the first time in Venezuela. Triaxial strength tests were carried at 72°F and 330°F to see the effect of high temperatures due to steam injection on stress-strain behavior, modulus and friction angle. This reservoir characterization at high temperatures was fundamental in analyzing problems of borehole stability during drilling as well as production in the injector and producer wells because of the mutual interaction due to the proximity of both wells. Of specific importance was the limiting flow rate of the steam injection well to eliminate hydraulic fracturing and the limiting production rate of the producing well to eliminate sand production and stability problems. The interaction and stability of both holes was evaluated with a fully coupled finite element program using Biot's poroelastic theory. This program was used to determine stability, stress and pore pressure values around the injector and producer wells under steady state conditions. The geomechanical analysis helped in defining the safe operating limits for the dual horizontal wells was useful to explain the behavior of some SAGD wells already in production in Tia Juana field and to plan for future ones.
Effect of Stress and Stress Path on Young´s Modulus and Poisson Ratio of Unconsolidated Rocks: A New Idea for Hydraulic Fracturing
Authors: Franquet Javier A. , Economides Michael J.
Published: December 2007

Triaxial testing of three unconsolidated sands extracted from Venezuelan petroleum reservoirs has shown a strong nonlinear correlation between Young´s modulus, Poisson ratio and the magnitude of the applied stress. While an elastic zone may appear at relatively small values of the stress, shortly thereafter a decidedly plastic region emerges. The Young's modulus declines asymptotically while the Poisson ratio increases when the differential stress increases. Numerical correlations are presented between the value of stress and Young´s modulus and Poisson ratio. Not only these quantities vary with the value of the stresses but they are also greatly impacted by the stress loading path. These variables would have a considerable effect on the evolution of the width of a hydraulic fracture and this effect is calculated and demonstrated. It is substantial. Hydraulic fracture widths are likely to be much larger than those calculated with a single Young´s modulus value. The rate of fluid injection, affecting leakoff and, thus, the state of stress is also investigated and its impact on fracture width is shown.
Recovery Of Heavy Oil From The Monterey Formation In Offshore California By Cyclic Injection Of Light Oil Diluent
Authors: Garnett R. L. , Dee C. L.
Published: December 2007

This paper describes a single well pilot in which light oil diluent was injected through tubing to lower in-situ oil viscosity and increase production from a low gravity oil well. The pilot well is located on the Heritage platform in the Santa Ynez Unit and produces from the Monterey formation. The pilot validated laboratory data which suggested that large production rate increases could result from high rate diluent injection.
Evaluating A Steam Flood Performance over a 7-10 Year Period Using 4D Seismic Attributes and Production Data-Duri Field Indonesia
Authors: Moore David , Rusdinadar Sigit , Widyantoro Adi
Published: December 2007

By 1997, multiple time lapsed 3D seismic surveys have become an integral part of the steam monitoring efforts in Areas 1, 4, 7, and 8 of the Duri Steam Flood EOR project. Continuing examination of the baseline 3D surveys (pre-steam) and subsequent monitor 3D surveys (8 months, 16 months, 24 months, etc.) have added to our understanding of how the steam moves within the reservoirs and to what extent production techniques can influence the steam direction.

Aerial conformance of the steam distribution for the Upper Pertama, Lower Pertama, and Kedua Zones in Area 4 was determined by the multiple seismic attributes of the 3D survey. The zones that show the most uniform steam distribution away from the injectors are those that are in structurally favorable positions (away from faults, low dip areas, on the axis of structural highs or lows) and in areas that have better sand development/connectivity around and away from the injector wells.

An economic analysis of the patterns with good sweep conformance of the steam have a higher DPI(discount profit index) than those that have poor sweep patterns. In area 4 the target DPI for the project was 1.3. The analysis of the patterns within the seismic survey of the western half of Area 4 shows that although the field average has a DPI of 1.4, there are a large number of the patterns that have DPI's less than 1.3 that seem to be related to the poorer structural and stratigraphic reservoir zones identified by the 3D seismic data.

The use of multiple time lapse 3D seismic data continues to prove its worth for tracking steam movement away from the injectors to the producers. This capability has enhanced our ability to control the steam movement at a pattern level by various steam reservoir management practices such a steam isolation, choke management, selective perfs and selective completion's, etc. However, those patterns that are located in areas of good structural position and stratigraphy are much easier to manage and require less human intervention provided the steam quality being injected is high.

By identifying these favorable areas in advance of steam injection for a given reservoir zone, one should be able to optimize the injector/producer patterns and achieve a higher rate of return for a given EOR steam project.
The Practice of Recovering By-Passed Oil by Horizontal Wells in Guan 2 Reservoir, Linpan Oil Field
Authors: Chen Yonghong , Liu Zhongyun , Zhang Yong , Han Xiangli
Published: December 2007

Guan 2 reservoir is located in Lin 2 block of Linpan oil field. The trip is a nose with a normal fault dipping towards North (Fig. 1). The reservoir consists of unconsolidated sandstone, which is a Tertiary fluvial deposit. The thickness of the sandstone reaches 140-150m, but only the top 15-30m reservoir is saturated by oil (Fig. 2). The depth of the initial oil water contact is 1426m from sea level. The reservoir oil viscosity is 76.5mPa.s.

Since the development started in 1973, 23% OOIP had been produced, and the water cut reached 92.7% under active bottom water drive. In order to improve oil recovery, a series of studies were carried out based on the 3D seismic, drilling, logging and production data.

According to the renewed understanding on the micro-structure, distribution and effect of the interbeds, advance of the oil water contact and the development of the water cones, the distribution of by-passed oil was determined. Then, 4 horizontal wells were designed and drilled. The results are inspiring. It is estimated that the ultimate oil recovery will be increased by 14.6%.

This paper presents the reservoir characters, the methods and results of the studies.
Single Trip Perforating and Gravel Pack System Reduces Formation Damage in Offshore Gulf of Mexico Wells: Case Histories and Guidelines for Candidate Selection
Authors: Jones Ralph H.
Published: December 2007

Improvements in the Gulf of Mexico (GOM) sand control completion methods have been and continue to be an ever-changing process. However, the goals have remained the same — to complete wells efficiently and generate the greatest production using the most cost-effective technology.

One of the new techniques that is available to operators to accomplish these goals is a method that allows perforating and gravel packing to be accomplished with a single trip into the well. This technique, the Single Trip Perforate and Pack (STPP) method, has recently been introduced to the industry. The purpose of this paper is to provide engineers and operators with a better understanding of when this technology should be applied. The method discussed will attempt to quantify the decision making process.
Impact of Completion Technique on Horizontal Well Productivity
Authors: Retnanto Albertus , Yamin Muhammad
Published: December 2007

Open-hole completions are certainly the one most commonly used since the early years of horizontal wells. It is still in wide use today although several other completion options are available. The main reason for alternative well completions is that open holes do not allow flexibility for zonal isolation, future well management, or problem remediation. Thus, partial completions can be envisioned. These can include slotted and blank liner, separated by external casing packers (ECP's) or segments of the well that are perforated, interspersed by segments that are left non-perforated.

The open length of the horizontal well can be reduced and, in many cases, without substantial decrease in the productivity index over a fully open well. This work, using a comprehensive multi- and single-well semi-analytical well performance model shows that for a relatively thin reservoir 40% open to flow distributed into 5 segments would result in over 90% of the open-hole ideal production with all the well exposed to the reservoir. In a reservoir five times as thick the normalized productivity index for the same 40% would still be a very favorable 77%. The length of open intervals can be optimized by balancing incremental production benefits against the costs of well completion. Complete stimulation of the full horizontal is very expensive and cumbersome, while fluid placement is frequently unsuccessful. Furthermore, the very necessary zonal isolation requirements for proper fluid placement are much easier in partially completed wells.
Development of Thin Oil Columns Under Water Drive: Serang Field Examples
Authors: Vo D. T. , Sukerim _ , Widjaja D. R. , Partono Y. J. , Clark R. T.
Published: December 2007

Exploitation of thin oil columns sandwiched between gas cap and water leg poses a unique challenge for reservoir development of many of such reservoirs worldwide, especially for those with high permeability and strong aquifer support. Issues important for reservoir management involve locating the current fluid contacts and optimizing well placement, as coning effects from both gas and water could severely hinder recovery.

The paper presents a field case study demonstrating the use of horizontal wells to improve oil recovery for thin oil columns affected by gas-cap and active water support. The paper discusses reservoir management practices applied, varying from use of reservoir modeling for identifying current fluid contacts to selection of completion strategies for optimizing oil recovery. A practical and cost-effective methodology involved, from reservoir modeling to landing horizontal wells, is discussed. Specific guidelines to complete wells in thin oil columns with respect to gas-cap size, well placement, spacing, well length, and rate control are provided.

Field data from Serang Field in the Kutei Basin of East Kalimantan are discussed. These examples demonstrate thin oil columns under water drive can be effectively exploited with horizontal wells via integration of technology and multi-disciplined team environment.
Case Study – Drilling a Horizontal Well in the Hutton Sandstone, Jackson Oilfield, Australia to Access Incremental Reserves in a High Water Cut Environment
Authors: Ogden Peter K.
Published: December 2007

The Jackson 33 DW1 horizontal well was the first horizontal well drilled in the Eromanga basin in South West Queensland by Santos Ltd. It was drilled in June 1998 in the Jackson Hutton reservoir to access incremental reserves that would otherwise remain unproduced within the field economic life. The Jackson Hutton reservoir is a mature oilfield with water cuts approaching 98% in the most prolific wells of the field. This paper will detail the reservoir, the identification of reservoir heterogeneity, the basis for drilling a horizontal well in the pool, the theory of mixed wettability allowing high recovery factors in the pool and how it relates to continued drilling and high volume lift, and the ultimate results of the well and the subsequent learning and future plans generated from its outcome.
An Infill Drilling Program to Identify and Produce the Deep Fluvial Channel Sands in the Raja Oil Field, South Sumatra
Authors: Berlandier Philippe , Safioedin Hermany , Sutrisno Bambang
Published: December 2007

Raja is a mature oil field located in the South Palembang sub basin of South Sumatra, Indonesia. The field has 20 to 30 independent vertical zones from the Talang-Akar (T-A) sandstone formation. Oil production started some fifty years ago, reached the maximum rate of 7000 BOPD in 1982-83, and then declined due to mechanical problems. The objective was to design and execute the well Raja-119 infill drilling program to produce "attic" oil trapped up in the ends of the deep fluvial N sand terminating in a pinch-out against the basement. The introduction reviewed the sand deposition model and the hydrocarbon migration systems. The paper then integrated the geological and reservoir features for preparing a realistic prospect (drilling target, reservoir geometry, original oil in place, remaining reserves, production forecast) and concluded with a discussion for interpreting differences between the forecast and the actual measurements. Well Raja 119 was successfully perforated in the N sand in December 1998. Infill drilling within risk analysis inside mature oil fields is a subject of global interest over Indonesia in general and South Sumatra in particular.
Comparison of Aerated Fluids/Foam Drilling Hydraulics Simulators Against Field Data
Authors: Nakagawa E. Y. , Silva Valter , Boas Mário B. V. , Silva P. R. C. , Shayegi S.
Published: December 2007

The application of light-weight compressible fluids in deep-water offshore operations will soon be a reality. An important factor in the design, accompanying and post-analysis of such a project will be the prediction of reliable downhole pressures, which are expressed in terms of Equivalent Circulating Densities (ECDs). Obtaining dependable ECDs for aerated (gasified) fluids and foam is more difficult than for single-phase fluids, since in the former ones the drilling mud has a gas phase in its composition. Drilling hydraulics simulators can be an important tool in the prediction and analysis of ECDs. There are both steady state and transient computer simulators available for ECD prediction, however their results need verification for different scenarios and different liquid/gas combinations.

In an effort to determine the most suitable simulator program for different well geometries, light-weight fluids and a range of liquid/gas combinations, real-time measured field data were analyzed and compared to bottom-hole pressures predicted by four different drilling hydraulics simulators. Additionally, the principle aspects of these drilling hydraulics simulators were compared based on the following characteristics: accuracy, user interface, numerical stability, and convergence.
Current Materials and Devices for Control of Fluid Loss
Authors: Ross Colby M. , Williford James , Sanders Michael W.
Published: December 2007

The purpose of this paper is to provide the oil industry completion engineers with a workable method for selecting the appropriate fluid loss control systems for their completions.

Fluid loss has long been recognized as a major concern when determining completion costs and assessing well management. For this reason, much research has been dedicated to investigating various methods and equipment to address the scenarios from which fluid loss results. Numerous papers have been written over the years on fluid loss control during well completion and workover. Many of these papers describe a specific method that has been used to address the problem, and a number of innovative devices and fluids have been developed. Most of these devices or systems have been addressed individually in the literature or as comparisons between products that are similar in design and function. Little has been provided on evaluating the merits of a variety of systems in an effort to provide a means of selecting an appropriate solution on a well-by-well or situation basis. This paper provides an in-depth discussion on the benefits, limitations, methods of operation, and possible applications for each of the methods and equipment currently in use.
Development of a Wireless Coiled Tubing Collar Locator
Authors: Connell Michael L. , Howard Robert G. , Moore Darrell W.
Published: December 2007

Achieving proper depth control with coiled tubing has been a problem since the service was introduced, and several improvements have been attempted with limited success. A newly developed tool overcomes depth-control problems by providing accurate depth locations of downhole devices. This tool allows real-time depth indication with standard coiled tubing, and requires no logging cable.
Implementation and Performance of a Microbial Enhanced Oil Recovery Field Pilot in Fuyu Oilfield, China
Authors: Ohno K. , Maezumi S. , Sarma H. K. , Enomoto H. , Hong C. , Zhou S. C. , Fujiwara K.
Published: December 2007

Since 1996, a Microbial Enhanced Oil Recovery (MEOR) field pilot is being conducted as a joint collaborative research project between Japan National Oil Corporation (JNOC) and Jilin Petroleum Group Company Limited (JPGCL) in Fuyuoilfield, Jilin Province, China. The primary objective was to increase oil recovery from a shallow sandstone reservoir that had been waterflooded for over 20 years.

Three microbes have been identified, evaluated, and put to test in the reservoir through huff-n-puff tests during which incubating conditions for microbes were optimized in surface facilities. Four tests with molasses only were conducted and evaluated against those with the microbial solution. Also, an advanced gene-targeting bio-technique, PCR-RELP, was applied to quickly identify and monitor the target microbes.

Significant reductions in watercut and increase in oil production rate were observed in most wells, and they sustained for over 6 months demonstrating the potential of MEOR process. Tests also confirmed abilities of microbes to survive and propagate under reservoir conditions. Preliminary evaluation of fluid analysis and production data indicates that they help increase formation water viscosity, lower water pH and produce gases, notably CO2. Additional huff-n-puff tests and laboratory studies using cores from two newly-drilled wells are underway. The implementation of the final phase of continuous MEOR flood is planned for mid-1999.
Angsi: Malaysia's 1st. Tight Gas Development
Authors: Gopalakrishnan Ganesh , Shawari Razli , Kassim Kamal , Naguib Ab Majid Mohd , Nor M. Nazri M.
Published: December 2007

Angsi Field, the first tight gas development in Malaysia is being developed for start-up in 2002 to meet gas supply commitments.

Productivity from hydraulically fractured wells and recovery from tight sands are major factors in Angsi development planning. An accurate assessment of the physics of fluid flow dynamics within this type of porous media is critical to project success.

A full-field model was constructed using an in-house reservoir simulation package. The objectives of this study were to assess the uncertainties surrounding the productivity of hydraulically fractured wells, expected gas recovery factors and other factors which could impede productivity and recoveries.

This paper discusses the reservoir simulation results and the optimum case that was used as the basis for the field development planning and describes briefly the pre-drill hydraulic fracture simulation design.
Reservoir Simulation of Waterflood Pilot in Naturally Fractured Spraberry Trend
Authors: Putra Erwinsyah , Schechter David S.
Published: December 2007

The Spraberry Trend Area in west Texas presents unusual problems for both primary production and waterflooding. Primary production under solution gas drive recovered less than 10% of the oil in place. After more than 40 years of waterflooding the current oil recovery is still less than 12%. In order to improve the reservoir performance in the Spraberry Trend Area, our studies focused on characterization, modeling and simulation of the Humble Waterflood Pilot. A pilot model was constructed using a three-phase, three-dimensional, dual porosity simulator (ECLIPSE).

Lack of understanding of two key issues are addressed, stress-sensitive permeability and rock wettability. These parameters appear to have a dominant effect in reservoir performance. This study emphasized detailed analysis of the stress-sensitive option used in the simulator by developing a numerical model of solid deformation and stress-pressure dependent permeability using a fully implicit finite-difference scheme. The numerical modeling of spontaneous and forced imbibition experiments using Spraberry core plugs were also conducted to investigate the wettability of the Spraberry matrix. These analyses may be helpful for understanding reservoir behavior and reducing uncertain parameters.

Several studies were conducted after successfully matching waterflood pilot performance. The waterflood pilot model was applied to run a series of sensitivity simulations for horizontal wells, well injectivity optimization, cyclic waterflooding, and other scenarios that could be useful to increase reservoir productivity. Based on results of waterflood pilot scenarios, this study may be able to provide guidelines for field development in the Spraberry Trend Area.
Plug-and-Abandonment Technique for Geothermal Wells Reduces Operators’ Costs
Authors: Courville Perry , Anderson Bryan
Published: December 2007

Because of the instability of the oil industry, operators must continually investigate new techniques and equipment to reduce operational costs. This paper will discuss four case histories involving an innovative well-intervention technique in which a coiled tubing unit (CTU) was used to deploy and set bridge plugs for plug-and-abandonment operations in geothermal wells. By using specially designed coiled-tubing (CT) tools, operators eliminated rig time and formation cooling time, thus reducing operational costs. When job designers assessed the job requirements and service options, they considered the following factors:In geothermal fields, pumping into a well to perform a kill operation for plug-and-abandonment techniques (required for conventional rig equipment) can affect the production of neighboring wells.Bradenhead pumping or pumping from the surface into a well for a kill operation is not always possible unless a kill string or workstring is deployed to a certain depth.The expense of rig time and production loss can affect operational costs.

Coiled tubing has been widely used in the oilfield industry because of its versatility and economy. When CT was first introduced, its primary advantage was that it could perform operations faster than a rig because of its increased pipe-moving capability. CT is now recognized for its capability to perform services with the wellbore in an underbalanced state. Specific tools that have been developed for CT operations have supported the increased scope of applications and have increased operational safety and reliability.

In the case histories presented, CT was used under live well conditions to deploy and set up 13 ⅜-in. bridge plugs for plug- and-abandonment procedures. Pressure-operated setting tools allowed entry into these geothermal wells under flowing conditions and allowed operators to successfully set drillable packer mandrels that have bridge plugs installed.

This paper will discuss the operation of setting tools, procedures for running the plugs, and obstacles that must be considered for operators to perform a successful plug-and-abandonment operation.
Application of Horizontal Well in Heterogeneity Gas Condensate Reservoir
Authors: Muladi A. , Pinczewski W. V.
Published: December 2007

As a result of a low pressure around wellbore, a liquid condensate saturation ring radially propagates the well reducing the relative permeability to gas. This phenomenon can occur even if the average reservoir pressure remains above the dew point pressure. Unless the pressure gradient stabilises around the well, the condensate ring continues to grow and the gas-oil ratio varies accordingly.

This paper presents application of horizontal well in heterogeneity gas condensate reservoir. Horizontal wells theoretically can improve productivity due to minimizing pressure drop around wellbore (higher PI). The primary goal of the study is to examine the difference in production performance between horizontal and vertical wells for different heterogeneities in gas condensate reservoir. Result demonstrate the effect of heterogeneity and average permeability values. It is shown that level of heterogeneity was found to have no effect in production performance but the layering pattern or distribution of heterogeneity was found to have more important effect.
A Successful Example of An Offshore Marginal Oil Field Development—A Case History of Wei 11-4 Oil Field in Beibu Gulf Basin
Authors: Hongji Yu , Shunqiong Song
Published: December 2007

During the feasibility assessment of development of the Weizhou 11-4 oil field, which is considered as a marginal field with no development potential by two foreign companies, we did our best to lower the geological risks and optimize the development plans. The field was proposed to develop by using irregular dense well pattern based on the existing development facilities and put it into production. During production drilling, completion and production, we modified the development program based on the variations of the geology and production performance, and obtained good economic benefits and thus achieve a successful development of a marginal field.
Exploration/Appraisal Well Drilling Experience in Block A-18 of the Malaysia-Thailand Joint Development Area.
Authors: Desa Mohd Latif , Anuar Anwar Hisham Zainal
Published: December 2007

Over a period of 3 years, beginning May 95, Carigali Triton Operating Company, Operator for and on behalf of PETRONAS Carigali (JDA) Sdn Bhd, Triton Oil Company of Thailand (JDA) Ltd, and Triton Oil Company of Thailand Inc., Contractor to Malaysia-Thailand Joint Authority (MTJA) for JDA Block A-18 have drilled a total of 16 exploration wells in the block.

The first well, Cakerawala 1A was spudded in May 1995 and the most recent well Bulan-3, was completed in July 1998.

Challenges, such as shallow gas anomalies, pore pressure uncertainties, tool temperature limitation, and lost circulation risk, have resulted in progressive well design changes. In general, most wells experienced abnormal pore pressure increases below 6,000 ft. The rate of increase differs between wells with the most extreme at 0.6 ppg/100 ft. Even though offset well pore pressure information exists, it served only as a qualitative guide.

Temperature was an important factor in the well design, especially mud selection. Temperature exceeding 400°F was recorded in one of the wells where oil based mud was used. This high downhole temperature had also resulted in frequent "cooling wiper trips" being required during formation evaluation activities to cool the wellbore due to logging tool temperature limitation.

The existence of shallow gas anomalies and lost circulation risk also contributed to the well design approach. However, by adhering to CTOC shallow gas procedures and by casing-off the loss circulation zones, the impact of these factors were minimized.

This paper will share and discuss the experience of CTOC in drilling these wells, such as well design changes during drilling to accommodate actual drilling results as well as the methods and procedures adopted to successfully drill these wells.
Progressive Cavity Pump-Jet Pump Production Method for Lateral Directional Drilling Well
Authors: Jun Zhu , Zheng Jiang Min , Fen Xu Xiu
Published: December 2007

To realize the high comprehensive production economic benefit of the lateral directional drilling well, one method, progressive cavity pump-jet pump production method, for lateral directional drilling well is studied in this paper. Its principle is introduced and the main characteristics are analyzed. The field test result for one well is given too. The experiment verified that the progressive cavity pump-jet pump production method has deeper pump setting depth and less investment cost and higher well oil-producing compared with other artificial lift methods. The progressive cavity pump-jet pump production method is one advanced and effective artificial lift method for the lateral directional drilling well's comprehensive economic production.
Use of Pseudosteady-State Pressure Distribution to Represent Wells in the Finite-Element Mesh
Authors: Lee Kun Sang
Published: December 2007

In calculating the long-time performance of depletion reservoirs using a numerical method, an accurate and efficient simulation highly depends on the proper grid selection. The treatment of wells can particularly have a strong influence on computed results. In our model, we use a very fine hybrid grid in near-well regions to obtain good resolution in the vicinity of wellbores. For the efficient simulation of field-scale problems with multiple wells of differing production rates, a well model was introduced to reduce the concentration of elements near wells. The model was based on a near-wellbore approximation of the pressure distribution during pseudosteady-state. Well performance calculated in the well model is correlated to the conditions in the appropriate location from the actual well. This approximation overcomes an inaccuracy for fluid flow calculation in the vicinity of wells and can be implemented easily in existing grids.

A numerical model based on the approach was developed for a simulation study. Numerical examples are presented to show the accuracy and computational efficiency resulting from the use of a well model. With the approximation, it was possible to reduce the number of element grid nodes up to 1/3. The level of error due to the approximation was in an acceptable range (< 4%) for all cases considered. The key element to the accurate calculation is the ratio of the effective radius of the near-well region compared to the distance to the nearest boundary.
Sepinggan Field Development: A Cross-Functional Team Effort to Develop Bypassed Attic Oil
Authors: Palar S. , Bowen J. F. , Elim A. , Leger K. P. , Simmonds B. , Fryns G. C. , Hursey M.
Published: December 2007

The Sepinggan SW project was conceived to remedy the problem of increasing water cut and a corresponding drop in oil production from wells completed in the Sepinggan SW fault block. It was felt that the SW fault block required additional delineation wells to determine the true downdip extent of the hydrocarbon column and to recover oil by-passed by the current production wells.

The initial idea was to drill long reach wells from the existing Sepinggan Field platforms. This approach however, had known drawbacks in terms of historically high drilling and completion costs, and a high degree of mechanical risk. Additionally, due to the required high angle from the long reach, some stacked pay potential may have been bypassed.

The cross-functional team working in the field conceived an idea of using existing Stacked Template Structure (STS) technology to provide easier wells to drill, with better well spacing, and dual objectives of drilling downdip appraisal wells and infill wells to maximize ultimate recovery.

This paper will show that due to close coordination among CFT (Cross Functional Team) members and support departments, the project was taken from concept to first production in approximately seven months.