bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hole Instability in Upper Zakum Field Offshore Abu Dhabi; Need Integrated Solution
Authors: Tantawi Ibrahim Yousef , Fadaq A. S. 
Published: December 2007

Abstract
Hole instability is one of the serious problems adversely affecting drilling efficiency and costs. Generally, it occurred in different forms as: shale instability, unconsolidated formation eroded by mud flow...etc. The shale destabilization is the worst type of hole instability.
In Upper Zakum drilling operations, shale instability is the dominant while drilling troublesome shale sections. The major shale sections are through Nahr Umr formations and thin shale streaks in Laffan, Halul, and top part of Thamma-I formations.
This paper is primarily focused on shale instability encountered while drilling ZADCO wells in Upper Zakum field offshore Abu Dhabi. It presents an investigation and engineering analysis of the main causes and different mechanisms of shale instability; chemical interaction, mechanical deformation. The chemical shale destabilization occurs due to the chemical reaction between the reactive clays and incompatible drilling fluid formulations. This reaction leads to the dispersion of reactive shale minerals into the drilling mud. On the other hand, the mechanical destabilization of shale may result from the unbalanced formation pore pressure, hole deviation, drilling practices, even in the absence of reactive shale. The related troubles encountered while drilling the problematic shale section are; excessive torque and drag on connection and while tripping, mud solids build-up and consequently unsteady drilling fluid rheology, stuck pipe, and hole enlargement that results in poor cement jobs.
Stuck pipe has costed ZADCO millions of dollars due to non-productive operational time involved in stuck pipe, fishing jobs, and side-tracking resulting from stuck pipe.
Detailed analysis of drilled wells and observations along with the result of laboratory tests show that hole instability due to chemical destabilization can be improved by utilising compatible drilling fluid formulation and good quality mud chemicals, and optimising mud rehology. To minimize hole troubles due to mechanical destabilization of shale; it requires proper pre-planning of the wells and careful implementation of the best practice are the key issues. Hole instability needs an integrated solution including; well trajectory, mud weight and formulation, design of bottom hole assemblies, mud solids removal etc. The main objective is to stay out of the trouble better than get out of trouble or prevention is always better than cure.
Gas Seepage at the Sea Floor: The Investigation and the Diagnosis
Authors: Fawakhiri A. Y. , Rouatbi R. , Mohamed F. H. , Boyd D. , Dajani N. , Okuyiga M. , Sherbini M. , Abu Shamat M. , Cabillic J. , Ramzi Darwish M. 
Published: December 2007

Abstract
A small gas explosion during the cutting of the 20″ casing on a well offshore Abu Dhabi, alerted staff to a potentially serious situation. Surprisingly, the well in an early phase of drilling, had not yet penetrated any known hydrocarbon bearing formations. Soon after the explosion, gas bubbles were observed emanating from the sea floor. A 70 milliondollar gas injection platform was at risk. Senior management reacting requested a multidisciplinary task force formed with a mandate to locate the source of the gas, the magnitude of the leak and the communication path to surface. A query to industry partners and regional oil companies sought their experience with similar situations. One company replied positively. Years earlier, it was afflicted with a well leaking gas to the sea floor. The mechanism and source of their gas leak was never determined as the leak ceased naturally. With at the time, no prior cases to guide it, the task force approached the problem through Cause Tree Analysis (CTA) and Decision Tree Analysis (DTA), together with Risk Assessment. Each of the four wells on the platform was scrutinized in turn. Historical data on pressures, production, cementing, tubular goods, logs run and other relevant data provided answers but also questions. As the Cause Tree evolved and further data collected, suspicions focused on one well. Additional evidence was needed. A program of noise/temperature logs and radioactive gas tracking produced unanticipated results. This paper focuses on the processes used to arrive at conclusions rather than the conclusions themselves.
Cementing the deepest 20 inch Casing in Abu Dhabi using a combination of Noval Light Weight Slurry and Fiber
Authors: Elmoneim Hossam A. , Zaki S. , Al – Arda Hussein 
Published: December 2007

Abstract
The Gas Khuff well is an offshore appraisal well drilled to explore the potential of gas production from Khuff formation. The drilling objective of this well is to penetrate the top Khuff formation at 13877ft down to the lower Khuff formation at 16335 ft with 8½ hole.
It was vital to drill 26 inch hole section throughout depleted water aquifers and weak fractured limestone formations, down to the deepest possible depth (5639 ft). Moreover, the long-term integrity of the gas well necessitated cementing the 20 inch casing up to surface with low permeability, high compressive and tensile strength, and lightweight cement without the use of stage tool. Meeting these requirements shall provide long-term casing protection against corrosion, isolate sour water aquifers and reduce potential of gas migration in the future.
Loss circulation problem encountered while drilling the 26 inch hole and large slurry volume exceeding the handling capacity of the rig and required to fill the annular space, were the main challenges in meeting these objectives.
A combination of Novel light weight slurry mixed at 1.2 SG (10 PPG) and fiber were used minimize the potential of losses during the cementing job execution. Meanwhile, additional bulk storage, mixing equipment and pump unit were mobilized to the rig in order to double the bulk storage capacity and handle large volume of cement slurry.
Experimental and Theoretical Assessment of the Asphaltene Precipitation Characteristics of the Sahil Field Under a Proposed Miscible Gas Injection Scheme
Authors: Jamaluddin A. K. M. , Nighswander J. N. , Kohse Bruce F. , Mahdi Ahmed El , Binbrek M. A. , Hogg P. F. 
Published: December 2007

Abstract
As part of the feasibility assessment for an improved oil recovery project on the Sahil reservoir in the United Arab Emirates, it was desired to assess the potential for asphaltene formation arising from the miscible contact of a rich hydrocarbon injection gas and the Sahil reservoir fluid. In this work, experimental data for the upper and lower asphaltene onset conditions over a temperature range from 110-255 °F were measured for the reservoir fluid. In addition, three injection gas mixtures (15, 45, & 60 mole%) were also evaluated at the reservoir temperature of 255°F. The experimental data were measured using a Near Infrared (NIR) light scattering technique. Subsequently, the experimental data was used to tune an equation-of-state (EOS) based model that represents the asphaltene phase as pseudo pure component solid. Results of the work demonstrated a significant effect of temperature and injection gas concentration on the asphaltene onset conditions for the reservoir fluid. It was also shown that the chosen model could accurately represent the measured behavior of the fluids over the range of conditions tested.
Microbial Phase Behavior Laboratory Studies
Authors: Zekri Abdulrazag Y. , Al-Khanbashi A. 
Published: December 2007

Abstract
During the past ten years, much attention has been focused on the using of microbial enhanced oil recovery (MEOR) processes by the oil industry. Very limited data has been published that reports the interfacial tension between crude oil and bacteria solutions and there is very limited laboratory work conducted on the phase behavior of oil-microbial systems. Microbial process is complicated and in order to apply the process successfully it is essential to perform an extensive laboratory work covering all areas related to the process mechanism. The MEOR bacteria transport through the water phase and congregate in pore spaces at oil-water interface where they metabolize a very small amount of the oil to produce various biochemical: surfactants, solvents, very week acids, polymers and gases (mainly CO2). These biochemicals decrease the interfacial tension between the oil and water, reduce oil viscosity, change the system wetability and in many cases improve the volumetric sweep efficiency by removing paraffin and scale blockage from pore throats.
This project focused initially on the study of the interfacial tension (IFT) between curds obtained from four different UAE reservoirs (AH, UZ, SH and UAD) and thermophilic bacteria solutions. The bacteria were obtained from UAE local environment Several crude oil/water/bacteria fluid samples were prepared. For these samples the salinity ranged from 0-100,000 ppm, and the crude oil concentration ranged from 10% to 90%. All systems were mixed very well and kept without any further agitation for one month. An optimum salinity was observed where a middle phase microemulsion was developed. Oil concentrations, keeping other variables constant, had no effect on the over all phase behavior of the studied systems.
Validity of Archie Equation in Carbonate Rocks
Authors: Talabani Soran , Boyd Douglas , El Wazeer Fathi , Al Arfi Saif 
Published: December 2007

Abstract
Archie (1941) found an empirical equation for consolidate sandstone relating some formation parameters, porosity and water saturation. Archie equation is not easy to apply to rocks because formation parameters (a, m and n) are fimctions of electrical tortuosity. Electrical tortuosity is determined by pore geometry, tortuousity of the pore system and wettability which, affects oil – water distribution in the pores.
Carbonate rocks with their complex pore systems and intermediate to oil wettability are difficult to describe petrophysically with a single a, m and n over a reservoir interval. Formation Resistivity Factor (FR) is highly variable. There is often no linear and direct relation between the resistivity index (IR) and formation water saturation (Sw) as the variably sized pores desaturate at different rates. These cases are labeled as non-Archie rocks. Archie is strictly valid only when the rock is strongly water wet, clay free and has a more or less uniform pore size distribution.
An important issue that Archie equation misses is the fluid critical point for multi – component state in which different phases co-exist. It is not clear how at reservoir conditions oil and water coexist in the pore system.
Development of a High-Speed Low-Torque Drilling Device
Authors: Cannon George E. 
Published: December 2007

Abstract
Research on Humble's high-speed low-torque equipment research project was originally handled by a research concern on a contract basis. Under this development contract three tools were built and considerable laboratory and field testing was done. Last year this tool was licensed to a bit manufacturer, and a development agreement was signed between them and Humble. Under these agreements two tools have been built which have been subjected to one laboratory test and seven field tests as of this date. A considerable history of mechanical failure has been developed, but as a result of the latest field tests it now appears almost certain that a commercial tool will evolve from this project.

Introduction
In 1949, a research organization located in Texas, undertook an investigation sponsored by an organization formed to investigate new methods of drilling to determine the applicability of high-speed low-torque cutting elements to the drilling of wells. This work encompassed a survey of the literature and patent art and a rudimentary laboratory investigation of the ability of a wheel set with tungsten carbide cutters about its periphery to drill rock when rotated about its axis with a flexible shaft drive and with the entire unit rotated about an axis 900 to the wheel axis. Drilling rates up to about 20 ft/hour were obtained in lime while drilling a 4 -in. hole with the experimental device.
This work was dropped by the sponsoring organization since it was felt to be too closely related to conventional rotary drilling practice and, therefore, outside the scope of the organization purpose. Since Humble had patent rights on a turbine-driven drilling tool of the type making use of such a cutting technique, Humble assumed the sponsorship of the development program. Under this development agreement and extensions thereof laboratory and field development work was continued through the fall of 1955. In the summer of 1956 a bit manufacturing company undertook further development of this tool.

Discussion
The original work conducted served merely as background since the work to be done for Humble was the development of a tool for field use. This required the design and building of a suitable surface test rig, determination of the most suitable materials for erosion resistance and cutting ability, and the development of operational techniques for use in the field. The tool was originally designed to drill 6 3/4-in. hole.
Removal of Wellbore Damage from Highly Permeable Formations and Naturally Fractured Reservoirs
Authors: Crawford David L. , Coulter A. W. , Osborn Frank E. 
Published: December 2007

Abstract
An acid system containing effective complexing and dispersing agents has proved to be highly successful in removing wellbore damage from highly-permeable formations and naturally fractured reservoirs. Case histories are presented for many wells that failed to respond to repeated clean-up attempts with conventional systems. Treatments using conventional acid, Mud Acid and diesel oil had been tried unsuccessfully. The wells did respond however to a system that incorporated special complexing agents with surfactant dispersants.
In addition to providing case histories, this paper will describe the nature of the special agents and their action and offer a possible explanation for their downhole performance.
One of the most difficult wellbore clean-up problems is encountered in gravel-packed wells. Sand movement and production must be controlled by gravel packing in many of the highly permeable formations in the Gulf Coast area. These gravel packs present an added barrier to overcome when bringing mud and solids back into the wellbore. Lost drilling mud, in particular, is difficult to flow through a gravel pack. The complexing-dispersing system described here has proved to be effective even under these conditions.
Designed Carrying Fluid Improves Gravel Pack Performance
Authors: Constien Vernon G. , Wallace Jim L. 
Published: December 2007

Abstract
Production of oil and gas from unconsolidated formations often results in the migration of formation material into the wellbore. A popular and effective method for stabilizing unconsolidated formations uses a high density gravel pack which is placed around a screen and out the perforation tunnels. A thickened, retarded acid system containing fluoboric acid has been developed as a carrying fluid for placement of the high-density gravel pack. This fluid combines the functions of gravel-carrying capacity, viscosity reduction, stimulation and clay and fines stabilization into a single fluid. Laboratory flow data on unconsolidated formation material demonstrates the stimulation and clay-stabilizing properties of this fluid. Field results are included which demonstrate the effectiveness of the fluid in high density gravel-pack treatments.
Downhole Protection of Sand Control Screens
Authors: Ledlow Lewis B. , Sparlin Derry D. 
Published: December 2007

Abstract
A widely acknowledged problem in gravel packing is plugging of wire wrapped screens and slotted liners Clays, drilling mud, cement, formation sand and pipe dope are all known plugging contributors.
Field tests and laboratory evaluations have demonstrated that an acid soluble screen protector material may be utilized to prevent plugging as well as replace wash pipe and to serve as temporary blank pipe or casing.
Design and Implementation of a Levelland Unit CO2 Tertiary Pilot
Authors: Graham Bill D. , Bowen Jerry F. , Duane Nick C. , Warden Gary D. 
Published: December 2007

Abstract
Amoco Production Company installed a contained 1.5 acre (6 070m2) tertiary pilot project in the Level land Field, Hockley County, Texas in 1978 in order to measure oil displacement that could be obtained by the carbon dioxide miscible recovery process in a completely waterflooded portion of the San Andres reservoir.
The pilot was located in a previously waterflooded portion of the reservoir. Sizing of the pilot was based on available log and core data utilizing a channel flow reservoir simulator which was designed to simulate miscible flood behavior. Special steps were taken during the drilling of the pilot wells to insure controlled placement of the bottomhole locations. Extensive reservoir delineation testing took place prior to starting carbon dioxide injection. Significant information concerning carbon dioxide process feasibility is anticipated from this pilot. Steps taken to design, install, and operate the pilot are described.
Review and Analysis of Past and Ongoing Carbon Dioxide Injection Field Tests
Authors: Goodrich John H. 
Published: December 2007

Abstract
Under a contract with the U.S. Department of Energy, Gruy Federal, Inc. has prepared comprehensive review reports for 19 projects in 16 fields in which carbon dioxide miscible injection was used to enhance oil recovery. Information from the geological and engineering literature, raw data from public records, and limited information supplied by project operators allowed nonproprietary review and analysis of 7 full-scale (i.e., commercial intent) field projects and 12 pilot projects. Abbreviated summaries of the field reviews for the full-scale projects are presented in this paper. Analysis and synthesis of the data and information from the field projects is also related to published CO2 flooding technology.
These data indicate that injection of CO2 is a technically efficient enhanced oil recovery process over a wide range of geologic and reservoir conditions. Hence, published technical guidelines for judging applicability of CO2 injection are probably too restrictive.
Biopolymer Injection into a Low Permeability Reservoir
Authors: Carter Walter H. , Payton Joy T. , Pindell Robert G. 
Published: December 2007

Abstract
Xanthan biopolymer has been shown to have effective mobility control properties in highly saline environments and to resist shear degradation. The use of this material in low permeability formations has been limited because of injectivity problems arising from the presence of cellular debris. This paper presents the laboratory evaluation and field testing of an enzymatic clarification process, and subsequent polymer injection in a low permeability carbonate reservoir.
The studies show that increased solution viscosity and improved filterability can be achieved by prehydrating the polymer in fresh water, that the enzyme treatment can be effectively performed under field conditions, and that the process can lead to adequate polymer injectivity in a low permeability reservoir when good water quality and effective quality control procedures are maintained.
The Effects of Pore Structure On Displacement Efficiency in Reservoir Rocks and in Glass Micromodels
Authors: Wardlaw Norman C. 
Published: December 2007

Abstract
In strongly wetted reservoir rocks, the extent of non-wetting phase trapping is strongly dependent on the geometric and topologic properties of the pore system. It has been demonstrated that pore-throat size ratio and certain types of heterogeneity affect displacement efficiency adversely. Throat to pore coordination number or connectivity and the condition or roughness of pore surfaces are other important factors affecting displacement efficiency.
Under conditions of intermediate wetting, pore geometry appears to be of reduced significance as a cause of trapping and, under these conditions, displacement efficiency is greater.
VHF Electrical Measurement of Saturations in Laboratory Floods
Authors: Davis Lorne A. 
Published: December 2007

Abstract
The changing oil/brine saturations along linear porous media during secondary and tertiary laboratory flood experiments have been measured using an electrical field detection technique. A short length of the cylindrically shaped medium is contained within the tank circuit capacitor of a very high frequency (vhf) oscillator operating above 100 MHz. The oscillator frequency is dependent upon the material's dielectric constant, which is a sensitive function of the oil/brine saturations.
The oscillator and associated electronics comprise a small, self-contained unit free to slide along the core barrel. A coaxial cable connects this assembly to an external frequency counter. Frequency (saturation) measurements can thus be made at arbitrary flood times and points along the porous medium. The cylindrical symmetry of the flow cell is advantageous, since it maximizes the pressure containment capabilities of the necessarily non-metallic core barrel materials.
The design and performance characteristics of this core saturation monitor (CSM) are described, and its response related to oil saturation and brine conductivity. Examples include saturation scans of a sand pack undergoing oil saturation and water flood. The utility of the technique is demonstrated by contrasting the oil movement characteristics of three chemical floods.
Retention Of Polyacrylamide By Berea Sandstone, Baker Dolomite, And Sodium Kaolinite During Polymer Flooding
Authors: Meister John J. , Pledger Huey , Hogen-Esch Thieo E. , Butler George B. 
Published: December 2007

ABSTRACT
Surface charge and accessible surface area control the retention of polyacrylamide by berea sandstone, baker dolomite, and sodium kaolinite. Hydrolysis of polyacrylamide increases retention by materials with a positively charged surface, such as dolomite, and decreases retention, when surface area remains constant, on materials with negatively charged surfaces, such as sandstone. Additives which form a more "theta" or less effective solvent promote retention. Water becomes a less effective solvent for polyacrylamide when its salt content is increased or when nonsolvents, such as alcohols, are added to it.
Berea sandstone cores retained over 50 percent of polyacrylamide injected under all salinities, polyacrylamide concentrations, and degrees of hydrolysis tested and sodium kaolinite retained over 90 percent of all injected polyacrylamide under the same conditions. In contrast, baker dolomite, a high purity dolomite, retains only 17.9 percent of the unhydrolyzed polyacrylamide injected. Since berea sandstone contains 7.5 percent kaolinite, these data suggest that clay content has a significant effect on total polymer retention.
Flocculating sodium kaolinite, which reduces its accessible surface area by over 80 percent, reduces retention by 70 percent, from 1,217 μg/g to 360 μg/g. With other variables held constant, reduction in accessible surface area will reduce retention of polyacrylamide by a porous medium as long as adsorption dominates the retention process.