bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application Of Hydraulic Fracturing Technologies To The Shallow Telisa Formation
Authors: Poerwanto J.H. , Sugembong C.F. , Bagzis J.M. , Martinez A.D. 
Published: December 2007

SPE Members

Abstract
This paper describes the changes that have been made to the stimulation treatments in the Telisa formation over the past year. The Telisa formation in the South Balam Field is a shallow (+/-600 feet), high permeability (10-100 md), laminated sandstone reservoir. The South Balam Field is located near the large Duri Field in central Sumatra. Hydraulic fracturing was initiated in the Telisa formation at South Balam Field in 1990.
Due to the shallow depth of Telisa formation surface treating pressure are typically 400 to 600 psi. These low pressure make pressure analysis very difficult. In many instances only 100 psi of net pressure is seen during the treatments. It is difficult to measure fluctuations in net pressure using only surface data. This has prompted the use of bottom hole pressure recorders with surface read-out which are more accurate and have higher resolution. The pressure recorders are hung inside tubing approximately 100 feet above the perforations, which eliminates pipe friction during the treatment analysis. The treatment are pumped down the annulus.
Minifracs were performed and analyzed using bottom hole pressure data to determine fluid efficiency, fracture closure pressure, and leakoff characteristics. Results of these tests have resulted in job modifications regarding pad and treatment sizes. History matching of treatment pressures, both post-frac and in real-time, have been performed using a hydraulic fracture simulator to determine created fracture geometries. Low level radioactive isotope tracer material was used to tag the treatments for determining the fluid and proppant distribution throughout the pay interval. The accumulation of this data indicates that hydraulic fractures in the Telisa formation are not horizontal, as expected for this shallow depth, but are vertical in orientation.
Additional treatment changes which were incorporated to increase fracture conductivity include pumping higher proppant concentrations, pumping increased proppant sizes and using higher quality proppant.
This paper indicates techniques and results which can be applied to other shallow high permeability sandstone reservoirs.

Introduction
The Telisa is the shallowest producing horizon in the South Balam Field, at an average depth of 600 feet, which is located approximately 50 km northwest of Duri Field in central Sumatra. Figure 1 is a structure map on top of the Telisa horizon.
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Near-Tip-Screenout Hydraulic Fracturing of Oil Wells in the Bach ho Field, Offshore Vietnam
Authors: Hung L. V. , San N. T. , Shelomentsev A. G. , Tronov J. A. , Lam D. D. , Thomas R. L. , Fox T. , Bisdikian C. 
Published: December 2007

Abstract
The first hydraulic fracturing of wells in Vietnam were successfully performed Offshore in the Bach Ho (White Tiger) Oil Field. Near-tip-screenouts rather than tip-screenout treatments were performed. The goal of the project was to improve production from existing wells rather than drill new wells and reduce the cost per barrel produced. This case study involves wells with multiple perforated zones completed in the Oligocene sandstone. Zones were selectively fractured in order to optimize production. A detailed description candidate selection, design, execution and evaluation processes are presented.
The Bach Ho field has been producing for 8 years but not at its potential due to various reasons including drilling and completion fluid damage. Although acidizing was an option for damage removal, hydraulic fracturing was selected as a way to bypass near-wellbore damage and generate a negative skin. Production simulators were used to quantify post-frac production. Due to suspected high closure stress, high strength proppant was selected and ramped in a high temperature fracturing fluid. Calibration treatments were conducted on several wells to quantify fluid leakoff, fracture height and Young's modulus. Based on the results of the calibration treatment, fracture designs were modified. As predicted by computer simulation, near-tip-screenouts occurred as planned.
The treatments were performed using a work boat with skid pumping/blending equipment, a computer monitoring/operation center and a laboratory. Strict QC procedures were followed to ensure the quality of all products.
Post-frac well tests results and production data are presented. Overall, the fracturing campaign was very successful with wells showing negative skins and up to a five fold increase of production in agreement with systems analysis predictions.
Experiences and Results of Acid Prepacking and Gravelpacking Wells in the West Lutong Field in Sarawak, Malaysia
Authors: Rajah Benny , Linder Ron , Todd Brad 
Published: December 2007

Abstract
Gravel packed wells in North Borneo have had a long history of impairment. The historical average skin factor for the wells in the Baram Delta area has been around 25.
As a result of the success reported in other locations, acid prepacking was chosen for field evaluation in the Baram Delta. Acid prepacking trials were carried out in the Bokor field with encouraging results. It was decided that the acid prepacking procedure would be used on all internally gravel packed zones during the 1992 – 1993 West Lutong field revisit campaign.
Flowing build-up surveys were ran on those zones that are currently producing. Because the wells are completed as dual selective, not all zones are available for testing. Good data is available for 13 of the 29 zones completed with the acid prepacking technique. The total skin values for the zones included in the analysis ranged from 1.3 to 20, with an average of 9.8 and an average removable skin of 6.6.
Combination Production of Vertical and Horizontal Wells
Authors: Jiali Ge , Demin Wang , Debin Qu 
Published: December 2007

ABSTRACT
In the last few years horizontal wells are becoming increasly important. This paper presents a hydrodynamic method for solving the flow problem of areal water–flooding systems of combinations of vertical and hprizontal wells( 5–spot well pattern and 7–spot well pattern). The potential function, production rate, breakthrough time, areal sweep efficiency and stream functions are derived respectively. Also, the flow resistance method is used for getting the equations of horizontal well production for all the areal floods. Finally, the equations of oil productions derived by the two methods are compared.
A Review Of Offshore Oil Fields Development in Malaysia
Authors: Seong Chen Kah , Hong Teh Yat 
Published: December 2007

ABSTRACT
This paper is a review of offshore oil fields development in Malaysia. Development of an oil field is typically divided into a number of major phases namely exploration and field appraisal, development planning, project implementation and field production. For an offshore oil field development, it requires careful planning and considerations during all of the phases. The requirements for field appraisal, subsurface development planning and facilities options are reviewed. During field production, special considerations are required to manage the field.
Reservoir Simulation of a high Viscous Crude and Strong Water Drive Reservoir in Sarawak, Malaysia
Authors: Ramli Adnan 
Published: December 2007

ABSTRACT
The Bokor field is located offshore Sarawak, Malaysia and is one of the largest fields in the Baram Delta Province (Figure 1). The A3/6 group of reservoirs is the largest amongst the Bokor reservoir groups. The reservoir comprises a series of multiple, stacked, well-developed, fluviomarine sandstones connected to a large aquifer. Production from this reservoir started in 1983 and since then some 15 MMstb of oil have been produced.
To better understand the production performance, displacement mechanism and further development opportunities in this high viscous crude (10 cP) and strong water drive reservoir, a 3D sector reservoir simulation has been carried out. The model comprises 8640 active grid blocks, with 14 strings completed on four reservoir units with separate fluid contacts. The layering system and grid dimensions were found to be critical in the history matching process, which was supported by a X-sectional study carried out prior to embarking on the 3D model.
Based on the history match, remaining oil was identified on the eastern flank, at the top of each sand unit (due to water under-running) and in the downdip area due to the existing ‘crestal oriented’ development. The history matched model was subsequently used to aid further development planning and to formulate a cost-effective reservoir management strategy. Various development scenarios were tested in this 3D model, which include infill drilling, horizontal wells and pressure maintenance by water injection.
This paper describes the various steps taken to obtain a good history match over the 10 years of production history and discusses the findings of the prediction runs.
Conservation Versus Realistic Economics
Authors: Deegan Charles J. 
Published: December 2007

The purpose of this paper is to sum up for you the economic point to which our technological progress in reservoir engineering has brought us; to analyze some of the current obstacles to more rapid progress; and to point out the broader responsibilities in the area of executive work that are more and more being opened to engineers.
With this group there is no need to trace the beginnings of reservoir engineering, nor to emphasize the accelerating rate of growth of our knowledge and understanding of its principles. Today reservoir engineering and it concepts are an accepted branch of oil producing technology; accepted by producers, by regulatory bodies, and by the courts. Its principles are inextricably woven into the general concept of oil and gas conservation. In fact the legal basis for acceptance of its findings by regulatory bodies and courts of law rests largely on the concept that application of reservoir engineering principles will result in conservation of oil and gas resources for the welfare of all the people.
Only a few of the new crop of engineers each year are unaware of the importance of economics in the practical application of reservoir engineering principles. The rest of you learned because management executives were always scrutinizing projects and laying down the law about the economic practicality of various proposals.
But that situation is changing rapidly these days. Many engineers are themselves part of management; others are in the process of being trained to become part of management. Therefore the detailed screening of the economic phases of reservoir engineering projects is being done more and more by engineers themselves. Top executives are apt to check only the overall figures and conclusions.
This is a highly desirable trend. But if it is to continue and accelerate, then engineers must become more executive minded in their thinking about the practical economics of reservoir engineering projects. They must display a willingness to accept responsibility for checking broader aspects and longer term phases of economic problems.
Let me cite an example of executive minded thinking about conservation projects. For many years now the elimination of flaring of casinghead gas has been recognized as a highly desirable conservation objective. Literally hundreds of people have talked and written about the subject.
Less than 10 years ago, two distinguished authorities in this field were testifying before a Federal Power Commission hearing on gas in Houston. Here is the gist of what they told the Commissioners at that meeting.
A price of 10 cents per thousand for gas at the well head will do more to stop waste and achieve true conservation than all of the actions of all the regulatory bodies in the country, plus all the public agitation on the question. Subsequent developments in gas prices and conservation results have served to emphasize the sagacity of these two men.
Field Trial of Simultaneous Injection of CO2 and Water, Rangely Weber Sand Unit, Colorado
Authors: Robie D.R. , Roedell J.W. , Wackowski R.K. 
Published: December 2007

Field Trial of Simultaneous Injection of CO2 and Water, Rangely Weber Sand Unit, Colorado.
D.R. Robie, Jr, J.W. Roedell, R.K Wackowski*

Abstract
The Water Alternating Gas (WAG) process is commonly applied in CO2 floods to reduce the mobility, to improve the stability of the flood front, and subsequently to improve recovery. There have been many modifications in the process over time to improve retention and operating conditions. Examples include tapering of the WAG ratio (an increase in the WAG ratio) and reduction of the half cycle slug sizes (the pattern hydrocarbon pore volumes of CO2 or water injected before switching to the alternate fluid.). At the Rangely Weber Sand Unit, WAG's at injection wells must be performed manually.
Simultaneous injection of CO2 and water (SI) is essentially the reduction of the half cycle slug size to the limit. Simulation suggested that improved recovery could be realized from the application of this technique. In addition, reduced half cycles were being applied at injectors in increasing numbers due to the reductions in the wide fluctuations in produced gas rates. This required additional time to manually switch the injection wells from one fluid to the other.
Based upon potential improvements in recovery and work force utilization, a field trial was implemented to verity that the process could be successfully performed. This paper reviews the testing of various processes to perform SI, as well as the implementation of a larger scale trial.

Introduction
The Rangely Weber Sand Unit is in Rio Blanco County in northwestern Colorado, U.S.A, about 5 miles east of the Utah-Colorado border (Figure 1). It is the largest field in the Rocky Mountains in daily and cumulative oil production. Currently, there are 372 active producers and 300 active injectors, 259 of which are injecting CO2.
Weber sandstone production was discovered at Rangely in 1933 by the California Company. Development of the field began in 1944 spurred by World War II oil demand, Initial 40-acre spacing development was completed in 1949. Infill drilling in the 1970's and 1980's reduced the spacing to 20-acre throughout nearly the entire field.
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An Oil Production Model for a Well Producing by Both Gravity Drainage and Viscous Flow From a Mature Steamflood
Authors: Owens B.K. , Ziegler V.M. 
Published: December 2007

B.K. Owens* and V.M. Ziegler*

Abstract
This paper presents a simple analytical model that determines the oil production rate for a well producing from a mature steamflood. Fluid flow in steamfloods exhibiting gravity override is frequently assumed to be dominated by gravity drainage, and viscous flow is considered insignificant. However, this paper presents a model that includes the effects of both gravity drainage and viscous flow. The model indicates that viscous flow or "steam drag" may be a significant force contributing to the oil production rate. Gravity drainage does dominate when thick liquid columns and low horizontal pressure gradients exist, but viscous flow may be dominant when the liquid column is thin. A reservoir may initially be dominated by gravity drainage, but as the reservoir depletes and the steam chest descends, the viscous flow force may become the dominant component.
Development of the model involves adapting a previous analytical prediction model that only considered gravity drainage. The new model can be set up to be handled in a spreadsheet.
Validity of the model is demonstrated by comparison of forecasts against Kern River field data. The first set of field data involves an entire steamflood project's performance after complete steam overlay has occurred. The second set of field data examines a situation where reservoir drawdown on several wells was decreased by shutting in a casing vapor recovery system. The final set of data deals with a scenario where reservoir drawdown was increased by installation of a casing vapor recovery system to an injector that was converted to a producer.

Introduction
Closmann presented an oil production model for a mature steamdrive that included the effects of gravity drainage and neglected viscous flow. The model was based on a reservoir where steam overlay has occurred and the steam zone completely covers a reservoir. Both Clossman and Vogel discussed situations where the viscous flow component was insignificant and the gravity drainage component dominated. However, since Kern River field experience shows that increased wellhead casing pressures result in decreased oil production, the viscous flow component is known to be sometimes significant. Therefore, Clossman's model was modified to include viscous flow. The resulting model tested favorably with three sets of field data.
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A New Analytical Model for Assessing the Role of Steam Production in Mature Steam Floods
Authors: Kimber K.D. , Deemer A.R. , Luce T.H. , Sharpe H.N. 
Published: December 2007

K. D. Kimber,* A. R. Deemer, T. H. Luce, and H. N. Sharpe*

Abstract
One of the keys to optimal steam flood operation lies in understanding the complex relationship between energy utilization and fluid flow phenomena. In assessing heat management strategies, it is important to consider not only the thermal requirements of the process but the impact these strategies may have on the mechanisms of oil production. It is important to know whether steam injection rate cuts, intended to reduce cost by supplying only the energy required for heat loss and steam zone growth, impact oil production rates and whether casing vapor shut-in will result in reduced oil recovery.
During the past two years, a study aimed at improving the understanding of the mechanisms affecting these critical questions was conducted. The investigation focused on the after-steam breakthrough stage of steam flood oil production. It helped identify the relative influence of gravitational forces and the additional force provided by the increased pressure gradient due to varying amounts of steam flowing between the reservoir and the production well during this stage. Several 3-D partially scaled experiments studying these mechanisms under conditions similar to the Kern River Field in California were completed. Numerical simulation and field data from operations at Kern River Field contributed to the findings. Study of the relationships between oil recovery and various steam flood mechanisms has led to the development of a new analytical model tailored to the after-steam breakthrough stage of the steam flood process. The contribution of each mechanism studied and the implications on field operating strategies will be discussed.
Using Geostatistics To Evaluate Cleanup Goals
Authors: Marcon Michael F. , Hopkins Loren P. 
Published: December 2007

Michael F. Marcon and Loren P. Hopkins

Abstract
Geostatistical analysis is a powerful predictive tool typically used to define spatial variability in environmental data. The information from a geostatistical analysis using kriging, a geostatistical tool, can be taken a step further to optimize sampling location and frequency and help quantify sampling uncertainty in both the remedial investigation and remedial design at a hazardous waste site. Geostatistics were used to quantify sampling uncertainty in attainment of a risk-based cleanup goal and determine the optimal sampling frequency necessary to delineate the horizontal extent of impacted soils at a Gulf Coast waste site.

Introduction
Statistical assessment of pre- and post remediation data is a critical step in evaluating contaminant characterization and attainment of cleanup standards. This paper discusses the incorporation of geostatistical methods in sampling strategies at hazardous waste sites. A Phase I Contaminant Assessment (conducted in two stages) completed at a chemical blending facility in the Gulf Coast indicated that eight compounds had significantly impacted superficial soils. A second phase sampling plan was developed using geostatistical tools and the Data Quality Objective (DQO) Process (1) to define the horizontal extent of contamination which exceeded preliminary remediation goals.
The purpose of the Phase II sampling plan was to identify all one half acre plots on the site which potentially posed an unacceptable risk to human health and the environment. The Phase II program was based on: preliminary remediation goals (PRGs) established during the risk assessment; the future land use for the property; uncertainty levels acceptable to both the Environmental Protection Agency (EPA) and the property owner; and the amount of expected concentration variability observed at the site. These inputs were used in a geostatistical analysis to develop a final sampling program to delineate the horizontal extent of contamination and eliminate the need for confirmatory sampling after remediation was completed.
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Multi-Temporal Environmental Analysis Of Oil Field Activities In South-Central Oklahoma Using Landsat Thematic Mapper, Aerial Photography And GIS
Authors: Janks J.S. , Edwards G.S. , Prelat A.E. 
Published: December 2007

J.S. Janks, G.S. Edwards, and A.E. Prelat

Abstract
Environmental assessments of oil field activities, historical and present, were made using a combination of Landsat Thematic Mapper, aerial photographic and GIS information. Landsat data was used to assess vegetation health in and around the oil fields, and aerial photography was used to document historic changes. We found no evidence of vegetation damage from the oil field activities, even though many fields are located along anticlines and drain into major waterways. GIS technology, mapping roads, wells, rivers, ponds and environmentally-sensitive areas, was used to minimize environmental effects on the placement of shotpoints and receivers. When either shotpoints or receivers were found to interfere with sensitive areas, the points were moved to nearby roads or other open locations. The application of this technology resulted in minimal environmental damage and significant cost savings.

Introduction
South-central Oklahoma has been the center of oil field activity since the early part of the 20th Century. The region is in part associated with the Ardmore basin, to the west of the Arbuckle Mountains (Figure 1). The many fields in the area, including Velma, Healdton, Sholem Alechem, Wheeler, Fox, Wildcat Jim and Velma are among the oldest in the country. Production comes from most of the permeable formations in the stratigraphic section.
Environmental practices have varied widely through the region's history, both within the oil field and without. Groundwater salinity gradients are sometimes reversed in this section of Oklahoma. Total Dissolved Solids (TDS) are 100,000 mg/L at the top and decrease to 1,500 mg/L at the base. All inverted water tables in the region have not been attributed solely to the effects of surface water pollution, as naturally-occurring inversions have also been documented.
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