bluuebunny/crossref_metadata_2025_split huggingface dataset:
Opportunities and Challenges for Enhanced Recovery in the Middle East
Authors: Wilkinson J. R. , Teletzke G. F. , King K. C. 
Published: December 2007

Abstract
A worldwide look at long-term trends reveals that new discoveries of conventional oil fields are declining while demand for oil is estimated to increase approximately 1.5% per year from the current levels of approximately 85 million bopd. The Middle East will provide a key role in future long term supply of oil to meet world demand. A portion of the increased demand will be met by increasing supplies from non-conventional deposits but the majority will need to come from improved rates and recovery in conventional oil fields. Industry experience and performance to date indicates that while considerable opportunities exist, there will also be fundamental challenges facing our ability to increase light oil recovery from complex carbonate reservoirs in the Middle East. For both host governments and industry partners, increased attention on fundamental parameters driving increased field offtake rates and recovery factors will yield long term dividends. This paper will discuss both basic technical parameters that need to be addressed and the improved/enhanced oil recovery (IOR/EOR) technologies that can be deployed (or developed) to meet this challenge. It also covers the pros and cons of various types of enhanced oil recovery injection fluids. Attributes of enhanced recovery fiscal regimes that are mutually beneficial to both host governments and the international partners will also be summarized. Successful implementation of projects will come from partnerships that capture unique strengths and abilities of all involved parties to increase Middle East production and help meet anticipated world demand.
From Concept to Pilot to Full-Field Implementation: A New EOR Process for the Prudhoe Bay Field
Authors: McGuire P. L. , Carini F. H. , Ambrose J. G. , Yancey A. N. , Panda M. N. 
Published: December 2007

Abstract
The uppermost 200 ft of the main pay interval at Prudhoe Bay is a moderate permeability, high net-to-gross fluvial sandstone which contains a number of thin, discontinuous shales. Most of this interval is being produced by waterflood and miscible gas WAG, but the updip third of Zone 4 has been produced by gravity drainage since 1977 and is very mature.
Fullfield models and material balance estimates indicated good recovery in the updip area. One Zone 4 core was taken in the gravity drainage area and one was taken in the waterflood/WAG area. Both cores were history matched with a reservoir simulator to determine the ultimate recovery potential of the process currently being employed. Detailed simulations indicated that the gravity drainage process was leaving high oil saturations behind the gas front which could not be produced economically because of excessive gas-oil ratios (GORs). Both water injection and miscible gas injection mobilized large volumes of oil and dramatically reduced the GOR.
The Updip Zone 4 Injection Project (UZI) is designed to mobilize and capture remaining oil trapped above the current gas-oil contact. In the updip area, both water and miscible injectant (MI) have been injected in Zone 4 while maintaining gravity drainage in the lower intervals (Zones 2 and 3). UZI patterns employ MI in a unique, highly efficient, single-slug oil swelling process rather than as a tertiary WAG. UZI injection has mobilized large volumes of oil and dramatically reduced GORs. The 14-01A pilot has produced roughly 2,000 BOPD of additional oil for the last 5 years from MI injection into a previously gassed-out producer. Total incremental oil from the MI pilot is approximately 3.5 MMBO.
The 1-11 water injection pilot is another success, with five of the eight offset wells producing an incremental 960 BOPD and 35 MMscf/D less gas. This major reduction in gas production has allowed increased production of about 700 BOPD from other Prudhoe Bay wells. A tracer program in the waterflood pilot has verified water containment within Zone 4. Based on this success, the Prudhoe Bay Unit has been expanding the UZI Project. Ten UZI patterns are already developed in the Eileen West End area. In the mainfield area, four patterns are currently on-line with another four patterns approved.
This paper briefly reviews the core analysis data and the reservoir simulation history match of the two Zone 4 cores and the process comparison studies. Production data from the updip waterflood and miscible gas flood pilot tests is presented, as is the performance of the early UZI patterns.
Five Years of Ongoing Conformance Work in the Central Mallet Unit CO2 Flood in West Texas Yields Improved Economics for Operator
Authors: Honnert M. , Creel P. , Tate R. , Everett D. 
Published: December 2007

Abstract
This paper reports the results of a 5-year effort to improve and enhance field-wide conformance. The developments on data analysis, reservoir and production engineering, and solutions in these mature units have provided the opportunity to make major impacts on recovery and production rates, operation enhancements, and cost reductions. The term "conformance" used in the context of this paper is given to mean "to influence the fluid flow that occurs in a petroleum reservoir." If we can gain influence over the action of formation fluids and introduced fluids and gases, we may have the power to bring more hydrocarbons to the surface and leave more undesirable fluids in the reservoir.
In 1999, a team was formed to solve field-wide conformance problems in a San Andres (dolomite) unit of the Slaughter Field, Hockley Co., Texas. The team's visualized goal was to improve unit economics by increasing oil production and decreasing production costs, using a better understanding of fluid movement through the project reservoir. The team was made up of both operating and service company personnel to accomplish the required data analysis, engineering, and solution designs that were required.
The original strategy was to form a full-functioning reservoir conformance team to identify, quantify, and fully describe field conformance problems. Focusing on the total reservoir, they developed a framework of data required to design a successful conformance solution. This data framework includes information of the reservoir, completion design, drilling and workover history, production and well-test history, logs and diagnostic analysis, and placement options. The framework also served as a tool to identify what data was lacking. An optimum conformance solution design was the team's vision.
This follow-up report based on the ongoing work over the past 5 years demonstrates the functionality of the methods and techniques used with a performance evaluation for defining successes thorough a review of the operator's economic drivers for sweep improvement, reduction of CO2, and water cycling-breakthroughs.
Why the LWD and Wireline Gamma Ray Measurements May Read Different Values in the Same Well
Authors: Mendoza A. , Ellis D. V. , Rasmus J. C. 
Published: December 2007

Abstract
Many concerns have been expressed regarding discrepancies between LWD (Logging-While-Drilling) and WL (Wireline) GR (natural gamma ray) responses in various wells. It has been suggested that these differences may arise from the variations in tool design that would be sensitive to the relative mixture concentration differences of Thorium, Uranium and Potassium between the University of Houston calibration test pits and the actual formations logged. Other causes have been attributed to errors in the characterization process and to the amount and accuracy of the borehole corrections algorithms applied to the measured values.
To answer these questions, we used the Monte Carlo code MCNP in combination with an in-house code, GAMRES, to simulate the response of the various gamma-ray detectors in a variety of LWD and Wireline tools. Each tool is sensitive to the Thorium, Uranium and Potassium concentrations depending on their particular geometric parameters such as NaI crystal size and thickness of the collar material surrounding the detector. To determine this sensitivity, an overall sensitivity coefficient is calculated for each tool at the time of calibration in a pit of known concentrations of Thorium, Uranium and Potassium. Under different borehole conditions (mud weight, barite mud, borehole size, etc), the tools would respond differently depending on their particular sensitivity. This modeling allows us to assess the difference in API units between the LWD and Wireline gamma-ray based on the tools geometric configuration, borehole size, Thorium, Uranium and Potassium concentrations, and mud weights both before and after applying the published borehole correction algorithms.
Results from this study indicate that significant response differences may arise, not from tool design differences, but from different borehole and/or mud conditions if appropriate corrections are not applied.
5K Dual Splitter Wellhead System: 1st Middle East Deployment on an Offshore Oilfield, Combining Simultaneous Production and Drilling on Adjacent Wells Within the Same Conductor
Authors: Santos A. , Floch A. 
Published: December 2007

Abstract
Splitter type Wellheads permit the drilling of two or more wells from within the same conductor pipe / caisson, resulting in significant savings for offshore drilling projects by potentially reducing both the size and quantity of wellhead platforms required for the field development.
In addition, on mature fields such as Total ABK, where no new slots exist and the installation of additional Wellhead platforms would not be cost effective, the addition of a cantilever deck to an existing platform and the use of a Splitter Wellhead system, presented a viable solution for an additional eight well slots, from four conductors.
From February to June 2005, two (four wells) Cameron nominal 13-5/8" 5K dual Conductor Sharing (CSW) systems were successfully deployed offshore by Total Abu Al Bukhoosh, using standard ABK well architecture of 13-3/8" × 9-5/8" casing strings, 7" liner and a 4-1/2'" gas lift completion with 4-1/8" 5000 psi Xmas Tree, from within a 36" conductor. A further two systems are being deployed since November 2005, to complete the current project.
All four wells of the Phase I project were installed, drilled and completed without any significant problems, ahead of the planned time schedule and under budget. The drilling and completion of these wells were performed under SIMOPS. Wells were put on production as soon as they were completed and were being produced while drilling and completing the other well on same conductor pipe. This resulted in savings equivalent to over a month of cumulative production per well.
Interpretation of Water Injection/Falloff Test—Comparison Between Numerical and Levitan's Analytical Model
Authors: Azarkish Abbas , Khaghani Elham , Rezaeidoust Alireza 
Published: December 2007

Abstract
Water injection/fall off tests are normally associated with water flood project. Recently, interested in this type of well tests has developed in the area of reservoir appraisal. In the vast majority of situations associated with exploration activities, there is no infrastructure and equipment in place to collect and export the hydrocarbon produced during well test. The common practice used in the industry is to burn the produced fluid.
The demands to reduce emission during well tests put enormous pressure to avoid these tests together. This brings large uncertainties to the reservior appraisal and increases the investment risk if a decision is made to sanction a project and to develop the field. Replacing a production/build up test sequence by an injection/fall off test sequence solves the problem of emission.
Levitan[1] stated that three main problems due to using water injection / fall off test might happen which are listed below:
The first problem is that the character of the system changes and Instead of single-phase flow we face now with two-phase water-oil flow by their own relative permeabilities. The second problem is injection of cold water includes temperature changes in the formation and brings additional complication to pressure behaviour through temperature effects on the oil and water viscosities and the third one is injection of water may result in the formation fracturing and in coupling of rock mechanics and fluid flow problems. It is therefore, important for successful test interpretation to avoid fracturing and to inject water at below the formation fracturing pressure.
This paper is divided into two parts. In the first part we are going to compare Numerical and Levitan's Analytical model for different injection and fall off periods using numerical part of Saphir well test software.
In the second part as far as we have validated Saphir Numerical model compared with W-O Levitan Analytical model, now this model is used to generate pressure responses in order to investigate the influence of reservoir parameters. Methods of interpretation will be used and some specific advantages of the numerical model will be shown.
A Review of Over 100 Polymer Gel Injection Well Conformance Treatments in Argentina and Venezuela: Design, Field Implementation, and Evaluation
Authors: Norman C. , Turner B. , Romero J. L. , Centeno G. , Muruaga E. 
Published: December 2007

Abstract
During the last 15 years, polymer gels have become an accepted technology for improving volumetric sweep efficiency in heterogeneous waterfloods. Water injected subsequent to the gel treatment ideally enters previously unswept zones with significant mobile oil saturation.
Results from several field projects in four hydrocarbon basins in Argentina and Venezuela are described based on the application of two available polymer gel technologies: Marcit℠ and Unogel. The types of reservoirs and reservoir conditions where polymer gels have been successful, and unsuccessful, are illustrated. Fundamental reservoir rock and fluid characteristics, reservoir temperatures, polymer gel designs, and project evaluation are presented for each of the field projects. A high temperature (275°F) reservoir is included.
In multi-layered reservoirs where crossflow is believed to be limited, one strategy is to inject a small gel volume in order to improve the vertical profile in the near wellbore region. If crossflow is believed to exist between layers or within a layer, significant gel volumes are recommended for deeper placement in the offending zones so that water cannot easily bypass the gel treatment.
Gel formulation is a fundamental issue. Traditionally, minimum polymer concentrations of at least 3000 ppm have been recommended for injection well gel treatments. Lower polymer concentrations were believed to be ineffective. A large scale and ongoing field project is presented in which low concentration polymer gels have been successful. In the same field project, the results of multiple gel treatments in the same injection well are discussed.
Lightweight Slurries—A Success Story of Application in Low-Fracture-Gradient and Depleted Fields for Improved Cementation
Authors: Dasgupta Debasish , Banerjee Satinath , Garg Satya Prakash , Jain V. K. 
Published: December 2007

Abstract
Till the recent times, covering the entire hydrocarbon bearing zones and simultaneously attaining quality cement bondage was a practical operational problem in the low fracture gradient and depleted fields of ONGC as the conventional lightweight slurries required for such conditions have low compressive strength, high porosity and high permeability which limit their application. Finding a feasible solution by developing lightweight cement slurry having adequate compressive strength was being investigated at the Institute of Drilling Technology (IDT) in ONGC for the past couple of years. Extensive studies performed culminated in the development of lightweight cement slurry systems for application in low fracture gradient and depleted formations to eliminate the losses during cementing and subsequent zonal isolation problem.
Formulated slurries inspite of low density have inherent properties of high compressive strength, low fluid loss, improved rheology, high stability, exceedingly low permeability and gas tight property. Field implementation results confirmed raising of long cement column without any losses and effectively encountering the perennial problem of cementing casings in low fracture gradient wells of Mumbai High in western offshore and CBM fields in India. A comparison of cementation with conventional and lightweight slurry system in the same field revealed better results with the latter.
This paper established the significance of application of these innovative lightweight slurry systems in terms of better well completion, reduced cost, improved productivity and less safety/environmental hazards in cementing across highly depleted zones and weaker formations. The details of the development, case studies of successful field implementation alongwith conclusions and recommendations derived from this endeavour are presented in this paper.
A Systematic Approach to Improved Success With Hydraulic Fracturing Applications
Authors: Jennings A. R. , Westerman C. W. , Tadlock D. W. , Westerman R. , Anderson M. 
Published: December 2007

Abstract
Methods to obtain better results with hydraulic fracturing in low permeability sandstone formations are constantly being developed. Fracturing techniques employed are often cyclic in nature, catalyzed to a large extent by gas and oil prices and corresponding costs of the stimulation treatments. "Optimization" of the fracturing approach may often seem arbitrary and raise the question: "Optimum …. Compared to what?"
Technology for improvements in hydraulic fracturing results is advancing at a rapid pace from the 3-D Seismic measurements used to define pay structure all the way to improved real-time mapping of fracture propagation. Extensive data gathering projects, however, are frequently big budget items and require dedication of manpower and resources. Therefore, such data measurement often tends to be reserved for projects of a regional scope.
This paper discusses several case studies of fractured wells in the Cotton Valley formation in East Texas and describes systematic changes in fracturing techniques used to improve treatment success. Comparisons of production data (short term and long term) are used to illustrate the degree of improvement. Readily available information (open hole logs, RA Tracer Logs, and PLT logs) was used systematically in this study.
Pitfalls in Performance-Data Tracking of Sucker-Rod Pumped Wells
Authors: Mahoney M. W. 
Published: December 2007

Abstract
Mean time between failure (MTBF) has been the standard for tracking field performance of sucker rod pumped wells but it can lead to improper conclusions and applications. A new method using cycle time and loading can greatly improve the understanding of the true performance of sucker rod pumped systems. Using proper data tracking of system performance and wear based on cycles and magnitude can greatly increase the understanding of a well system and be a proper guide to optimization.
Monitoring Multilayered Reservoir Pressures and Gas/Oil Ratio Changes Over Time Using Permanently Installed Distributed Temperature Measurements
Authors: Brown G. A. 
Published: December 2007

Abstract
Early identification of differential depletion in stacked reservoir sands, before water or gas breaks through, is the key to optimal reservoir drainage. However, hitherto it has not been possible to monitor reservoir pressure changes in individual layers after a well has been put on production without installing an intelligent completion or performing a multirate inflow performance relationship (IPR) test.
This paper describes a technique allowing individual layer pressures, or gas/oil ratios (GOR), to be monitored continuously during production. The technique employs the use of a rigorous near-well nodal reservoir pressure and thermal model to analyze permanently installed distributed temperature measurements. By modeling a range of typical flowing scenarios we demonstrate that distributed temperature measurements respond to changes in production caused by depletion in individual reservoir layers. We also show that in addition to flow rate determination, layer pressure changes smaller than 10 psi can be detected by changes in the measured temperature profile, as long as there is no breakthrough of gas or water. The model is also used to define the limits of the technique's operating envelope.
Increases in the flowing layer GOR will decrease the layers' fluid viscosity, resulting in a change in flow rate together with a decrease in flowing fluid temperature due to the Joule-Thomson effect. Consequently, layers where the GOR increases, identifying early gas breakthrough or fingering, can also be detected using distributed temperature monitoring.
The theoretical models are supported by real well examples, where the calculation of different layer pressures caused by depletion is confirmed by shutting in the well and observing the resulting crossflow with permanently installed distributed temperature monitoring. These models, along with continuously monitored temperature profiles, can be used to refine reservoir models and thus improve overall field recovery.
Uniform InFlow Completion System Extends Economic Field Life: A Field Case Study and Technology Overview
Authors: Lorenz Michael , Ratterman Gene , Augustine Jody 
Published: December 2007

Abstract
Horizontal wells on a global basis continue to serve as a primary well type for improving recovery efficiency, increasing reservoir drainage area, delaying water and gas coning and increasing production rate. However, in longer, highly deviated and horizontal wells, non-uniform flow profiles can result in premature water or gas breakthrough, screen plugging and erosion, which can shorten well life and decrease well profitability.
This paper describes historical and new applications of a proven production technology system that optimizes production, delays water and gas coning, minimizes annular flow to prevent erosion and ensures uniform inflow along the lateral at the cost of a minute pressure drop in high-rate horizontal wells. Case histories will be presented from the Norwegian Sector of the North Sea and offshore Saudi Arabia, where this production technology, combined with sand-control technology, has resulted in significant savings for the operator and improved production in horizontal offshore oil wells.