bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Optimization by Combined Artificial Lift Systems and Its Application in Two Colombian Fields
Authors: Borja Hubert , Castano Ricardo 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.