bluuebunny/crossref_metadata_2025_split huggingface dataset:
Economic Evaluation of Enhanced Oil Recovery
Authors: Zekri Abdulrazag Y. , Jerbi K. K. , El-Honi Mohamed 
Published: December 2007

Abstract
The research for tomorrow's oil reserves has directed the efforts of the energy industry to frontiers beyond the conventional exploration and production strategies. Frontier defined not by geography or geology but rather by technology. This frontier is a collection of technologies-involving the use of thermal, gas and chemical means for producing more oil-that fall under the broad umbrella called Enhanced Oil Recovery (EOR). The results of successful application of this new technology will have a decisive impact on the energy conservation program of any oil producing country.
A comprehensive national energy program is complex and to plan it represents a challenge. A unified and complete national program must encompass the consideration of all possible options. The potential of each need to be explored. One such option in Libya is to produce more oil, that is, to effect the enhancement of oil recovery from the nation oil fields. The planning of an EOR project demands a meticulous attention to many problems, thus requiring considerable lead time for studies, evaluations, project design and most of all the economics of these high cost EOR projects.
The objective of this study is to conduct an economic analysis on one of the most representative candidate major field in Libya (D field) for application of the technically approved Enhanced Oil Recovery methods. By performing economic sensitivity analysis on key input variables such as oil prices, the price of injection solvent, capital expenditures, operating expenses, and oil recovery with the aim to develop sensitivity analysis graphs for each variable to assess future engineering planning with regard to the EOR projects economics in Libya. Economic optimisation is the ultimate goal of reservoir engineering management. With estimated production, capital, operating expenses, and financial data, project economics are evaluated. Project finding could be applied to any EOR candidate reservoir worldwide.
Case Studies on Application of Novel Guideline Charts in Planning Well Trajectory and Mud Weight Program
Authors: Chen X. , Tan C. P. , Haberfield C. M. 
Published: December 2007

Abstract
Wellbore instability remains an important and costly issue in many oil and gas fields. Field observations have shown that stress-related wellbore instability problems are still frequently encountered even though techniques to manage the problems have been adopted. The problems can be a main factor in reducing the benefits of introducing innovative drilling technology.
This paper describes the methodology and procedures for determination of optimum wellbore profile and mud weight program based on rock mechanics considerations. The comprehensive methodology, covering all key aspects of wellbore instability, is presented in the form of guideline charts. The application of the methodology and procedure is described and demonstrated through three field case studies for a range of in-situ stress regimes in various parts of the world.
Sand Production Simulation in Heavy Oil Reservoirs
Authors: Zhang Liangwen , Dusseault Maurice B. 
Published: December 2007

Abstract
A new sand production model is developed based on inter-particle contact force variations at the discrete micromechanical level. Two mechanisms for sand production can be expected in the field, dynamic detachment and equilibrium yield. The model discussed in the paper describes the sand production mechanism in the dynamic detachment process. Within the new model formulation, sand is considered to be produced because of either a large porosity gradient or a large pressure gradient. The 1-D steady-state solution of the new model is also presented; it may be used for simple sensitivity analysis for parameters such as the field stress and pressure depletion effect.
Application and Development of Drilling and Completion of the Ultrashort-Radius Radial Well by High Pressure Jet Flow Techniques
Authors: Li Yonghe , Wang Chunjie , Shi Lianhai , Guo Weiyi 
Published: December 2007

Abstract
Ultrashort radius radial well drilling and completion technique by high pressure jet flow is referred to as the Ultrashort radius (0.3meter) radial horizontal well drilling and completion techniques. It can be applied both in new and old wells. Its main technique is to use high pressure jet flow energy, given by a special high pressure jet tube, to penetrate and elongate a number of lateral well bores radiated from the main well bore in the same layer (or different layer) so as to expose the pay zone as much as possible and increases the EOR.
This paper has described three key parts of high pressure jet flow technique for ultrashort radius radial well drilling and completion: big diameter underreaming technique; design principle of diverting system; and option of well completion methods. And introduces whole process and key parts of this technique combined with its application results in Jin Well#04–19 and Jin Well#38–303 of Liaohe Oilfield. This paper has also briefly depicted the future development of this technique in the Oilfield and its main problems must be resolved later, as well as its economy and feasibility.
Minimize Sand Production by Controlling Wellbore Geometry and Flow Rate
Authors: Samsuri A. , Chuong P. V. 
Published: December 2007

Abstract
The production of sand particle has become serious problem to oil and gas well and was subject for study during the past years. Basically, sand production must be the results of a change in strength of the formation rock due to drilling, perforation and production operation and drag forces of the produced fluids. Therefore, during designing and developing stages, parameters related to sand production need to be examined carefully. This paper presents an experimental study of the effects of wellbore geometry and flow rate to sand production and total oil recovery; to minimize sand production as well as optimize production. The experimental works include of static and dynamic sand production tests, which were carried out on wellbore models with different wellbore angle, perforation shot density, and perforation pattern and flow rate using Servo Control Compression Testing Machine (SCCTM). The results show that oil production is reduced as sand production increases and most of produced sand are large size indicating the dominant effects of the breakage of cementing materials. Sand production increases significantly after effective stress reaches 35–60% of rock compressive strength and followed by the reduction of total oil recovery to 55–73%. In addition, sand production increases as wellbore angle, shot density, flow rate increase and as perforation pattern change from spiral to inplane and finally inline, especially for model with more than 10° well bore angle, inline pattern and 1600cc/h flow rate. Therefore, in order to optimize production, sand production must be minimized by reducing wellbore angle (&lt;10°), shot density, flow rate (&lt;1600cc/h), perforated with spiral pattern and pore pressure should be controlled so that effective stress around a wellbore is not more than 35% of rock compressive strength.
A Feasibility Study of Time-Lapse [4D] Seismic Monitoring of Water Injection Recovery Processes
Authors: Zhou Chengdang , Liu Wenlin , Chen Shuzhen , Li Fanhua 
Published: December 2007

Abstract
Water injection is the most commonly deployed recovery method in most Chinese oilfields. Efficiently monitoring production behavior in the water injection recovery processes is essential to improving water injection efficiency and enhancing oil recovery. Currently, time-lapse seismic reservoir monitoring(TLSRM) is widely used in reservoir monitoring. However, only the reservoirs whose seismic response changes caused by their internal fluid changes are large enough, compared with seismic noise, are suitable for time-lapse seismic surveys. So it is necessary to do a feasibility study of time-lapse seismic before starting a time-lapse seismic survey. Fluvial and delta facies reservoirs are the primary depositional facies types. In this paper, a numerical reservoir simulator is used to simulate the fluid flows in the water injection recovery process in a fluvial reservoir, and Gassman's equation is used to generate synthetic seismograms corresponding to different recovery time. By analyzing velocity and impedance differences between synthetic seismograms of different production time with reservoir physical parameters, the feasibility of TLSRM of the water injection recovery process of the interested reservoir is studied.

Introduction
Water injection is the most commonly deployed recovery method in most Chinese oilfields. Production in the water-injection oilfields can be divided into three stages: primary production, stable production and descreasing production stages. Since the reservoir recovery time without water-injection is short, recovery with high water cut is the main stage in the reservoir recovery process. And the main method maintaining production in the high water-cut period is the proper adjustment of oil recovery projects. Efficiently monitoring production behavior in the water injection recovery processes is essential to proper adjustment of recovery projects, improving water injection efficiency and enhancing oil recovery. Both fluid production and injection in the recovery processes will result in changes of reservoir physical properties which, in turn, lead to changes of the associated seismic properties and responses. Through analysis and comparison of seismic data repeatedly acquired at different time at the same place, time-lapse seismic can visually indicate the changes of reservoir physical properties in the recovery processes, realizing monitoring of dynamical behavior of recovery processes. However, only the reservoirs whose seismic response changes caused by their internal fluid changes are large enough, compared with seismic noise, are suitable for time-lapse seismic surveys. So it is necessary to do a feasibility study of TLSRM before starting a time-lapse seismic survey.
Bridging Adsorption of Cationic Polyacrylamides in Porous Media
Authors: Denys K. , Fichen C. , Zaitoun A. 
Published: December 2007

Abstract
Recently, cationic polyacrylamides (CPAM) have been successfully applied in water shutoff treatments of oil and gas wells. These polymers adsorb strongly on reservoir rocks, building up an adsorbed layer of significant thickness. Moreover, under high rates, the coiled macromolecules stretch and can bridge large pore throats. This so-called bridging adsorption mechanism has been described previously for high-molecular-weight non-ionic polyacrylamides (PAM).
CPAM rheology and retention behavior has been studied in unconsolidated SiC packs and in Berea sandstones in a permeability range 0.1-1 D with CPAM solutions having a cationicity between 0 and 50%. Due to the attraction between the positive charges carried by the polymer chain and the negative surface charges of the rock, both CPAM adsorption and bridging adsorption are higher than for PAM having the same molecular weight. A maximum adsorption is found around 10-15% cationicity. This maximum, observed both in SiC and in Berea, is due to the competition between adsorption energy and pore wall accessibility. Although the permeability to water drops considerably after CPAM bridging adsorption, the permeability to oil is remarkably preserved, which makes CPAM attractive for water shutoff applications.
Modeling Acid Returns Profiles After HF Acidizing Treatments
Authors: Gdanski Rick 
Published: December 2007

Abstract
A comprehensive HF (hydrofluoric acid) acidizing radial-flow model has been modified to accommodate deep-matrix mixing and backproduction of spent acidizing fluids. The model has successfully matched the published ionic returns profiles of several HF acidizing treatments. The model was used to demonstrate the magnitude of fluid mixing within the matrix. It was shown that approximately two treatment volumes of aqueous production are required to recover most of the original treating fluid. The impact of mixing and ion exchange on lowering produced fluid pH long-term after acidizing treatments was also demonstrated. A hypothetical HF acidizing treatment was modeled and used to demonstrate the ionic profiles within the matrix that result from the various reactions and precipitations. The ionic profiles that would be observed in spent-acid returns were then modeled to provide a general view of typical returns compositions. Field acid returns were matched with the simulator, and they demonstrated that information about formation mineralogy and reaction kinetics can be obtained.
Novel Application of Synergistic Guar/Non-Acetylated Xanthan Gum Mixtures in Hydraulic Fracturing
Authors: Fischer C. C. , Navarrete R. C. , Constien V. G. , Coffey M. D. , Asadi M. 
Published: December 2007

Abstract
Fracturing fluids have traditionally been viscosified with guar and guar derivatives. Non-acetylated xanthan is a variant of xanthan gum which when combined with guar in solution develops a synergistic interaction that generates superior viscosity and particle transport at low polymer concentrations. These water-base linear fluids have improved low shear viscosity at concentrations at or below 25 lb/1,000gal when compared to fluids viscosified using a single viscosifier such as guar or xanthan gum. The polymer mixtures can be crosslinked to provide enhanced viscosity at higher temperatures.
Hydraulic Fracturing Treatments In The Buena Vista Hills Field
Authors: Erickson J.B. , Kumataka M.K. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Several fracture treatment designs have been tested in the Buena Vista Hills Field in order to determine the most desirable program. Field experience and laboratory analyses show that untreated lease oil is more successful than other fracturing fluids. Current treatment methods are more effective than earlier techniques in controlling sand production and reducing rapid production decline rates. Recent stimulation efforts are economically successful and have encouraged further development of the field.

Introduction
Two low permeability sand formations in the Buena Vista Hills Field contain large amounts of oil-in-place, but primary recovery is less than satisfactory. Since 1964, fracture treatments have been performed in these zones to improve recovery, with varied results depending upon field location and treatment design. Programs using both water-base and oil-base fracturing fluids in gelled and ungelled solutions have been tested. The ungelled lease oil treatments have shown favorable response in specific areas of the field. None of the water-base fluid treatments have been successful.
The current fracture stimulation programs have evolved through a combination of field experience and reservoir analysis. Based upon past experience, ungelled lease oil is exclusively used in these programs. A few changes have been made concerning the size and amount of frac sand, and the results have been encouraging. Recent treatments appear to show slower decline rates than earlier treatments, and the problem of sand production following some of the early treatments has been eliminated. Currently a typical fracture treatment consists of 200,000 pounds of frac sand (75% 50x70 and 25% 8x12) in 50,000 gallons of untreated, 26 deg. API lease oil. The increase in production after frac oil recovery averages 25 BOPD and 150 MCFPD, which pays out the treatment in approximately two months.
This paper presents a history of fracture treatments performed in the Buena Vista Hills Field, and discusses the development and sults of various treatment designs.

GEOLOGY AND RESERVOIR DATA
The Buena Vista Hills Field is located near the southwestern edge of the San Joaquin Valley, about 45 miles southwest of Bakers-field, California.
A Technique to Estimate EOR Production from Routine Oil Samples
Authors: Moulds T. P. , Riggert V. L. , Lee S. T. 
Published: December 2007

Abstract
A method is presented which calculates EOR oil rate using compositional data from the produced oil stream together with a reservoir fluid equation of state. The method uses the produced oil composition to calculate molar volume and then interprets the molar volume signature in the context of reservoir geology and flow dynamics. This leads to a quantitative estimate of EOR oil volume and qualitative insight to the MI sweep pattern.
The method is extended to use API gravity input rather than molar volume. The results are equally good when using API gravity. Routine sampling for API gravity is relatively cheap so this opens the possibility of a cost effective method to directly measure EOR oil. The potential of this method is to greatly enhance the quality of information concerning flood performance so enabling more effective flood management.
The method is illustrated using several fine grid simulation models with widely varied reservoir descriptions which were built to evaluate the Prudhoe Bay Miscible Gas Project. In all cases, the EOR oil production from molar volume or API gravity analysis is within about 1% OIIP of the EOR recovery estimated from separate waterflood and WAG simulations.
Integrated Reservoir and Production Management: Solutions and Field Examples
Authors: Bøe Arild , Nordtvedt Jan-Erik , Schmidt Harald S. 
Published: December 2007

Abstract
Reservoir and production monitoring and control devices are critical components for better reservoir management. These devices being important for understanding the state of the reservoir as well as for optimizing its exploitation, their availability and utilization has grown and is still growing. Also, the increasing use of topside/subsea metering systems provides important information on the production characteristics. All these devices can now be logged and controlled remotely in real time. As a consequence, it is now technically possible to manage the reservoir exploitation process fully automatically from a remote location. This paper outlines how logging of data, analysis of data, and control actions, can be implemented remotely and in real time for improving reservoir and production management. Also, we discuss three integrated reservoir and production management field case designs.
A Caustic Steamflood Pilot-Kern River Field
Authors: Robinson R.J. , Bursell C.G. , Restine J.L. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
From October 1973 to June 1976 a caustic steamflood pilot test project was operated in the Kern River Field of California. The test was conducted in nine adjacent five-spot patterns and utilized Sodium Hydroxide as an patterns and utilized Sodium Hydroxide as an additive to the injected steam.
The purpose of this paper is to present and discuss the operation and results of the pilot project. Initial research and planning pilot project. Initial research and planning processes are described in addition to processes are described in addition to comparison of the pilot production response with other similar patterns in the same area of the field.
Tracer and testing programs were initiated in the later stages of the pilot to provide additional data for analysis of the provide additional data for analysis of the project response. This information is project response. This information is presented along with discussions which presented along with discussions which describe the behavior and movement of the Sodium Hydroxide through the reservoir.
From the results of this pilot, recommendations are made concerning laboratory testing and field applications of chemical additives in a steamflood project.

Introduction
The use of a caustic additive for enhancement of oil recovery has been suggested, discussed and tested for several years by various individuals. Most of the literature focused on enhancement of waterflood response by using a chemical additive that would either change the interfacial tension between oil and water, adjust the wettability of the reservoir system, or increase sweep efficiency, all of which can be accomplished with a caustic.
Numerical Modeling Of The Wairakei Geothermal Reservoir
Authors: Horne Roland N. , O&apos;Sullivan Michael J. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
In order to achieve a better understanding of the Wairakei geothermal reservoir and of others of similar type, the current investigation considers the problem of a hypothetical geothermal aquifer that depletes the fluid saturating its upper regions during production. This depletion leads to the characteristic depressurization and drawdown of the liquid surface observed at Wairakei. This effect is significant in that the subsequent appearance of a horizontal pressure gradient may cause the premature shutdown of the bore field due to the premature shutdown of the bore field due to the encroachment of colder ground water.
In fact, the results of the modeling show a different behavior, emphasizing the vertical movement of the saturating hot fluid as a more important effect. The model gives an indication of the time the reservoir will take to reach pressure equilibrium and its output at that pressure equilibrium and its output at that time.
Problems associated with the numerical procedures are considerable even though the procedures are considerable even though the model is single phase and axisymmetric, and the value of such an intricate numerical model is tenuous. By using a simpler model, replacing the moving surface by an encroaching region of cold water, it is possible to obtain a lower bound for the useful-life of the system and also to examine the possible effects of recharging the system.

Introduction
The numerical investigation of geothermal reservoirs has been performed on one of two levels - first, attempts to model exactly all the geological properties and fluid and thermo-dynamic behavior of the system or, second, fundamental models that include only the effect deemed significant. Although some success has been made with the first approach, for example, the comprehensive, two-phase, rock matrix interaction model of Garg et al. and the simpler model of Mercer and Faust, the current investigation favors the second approach. There are advantages in avoiding a full simulation since little information concerning the physical system is available from below the level of the well bases, so that it is only possible to represent conditions in the upper possible to represent conditions in the upper reservoir.