bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of Borehole Quality, Diameter and BHA Directional Response: Eccentric Tool Test Program for Expandable Casing Application North Sea
Authors: Lodder Robert Jan , Ruggier Michael , Sinor Allen , Bobrosky Douglas , Radford Steve 
Published: December 2007

Abstract
A detailed test program was performed with an eccentric tool at the Baker Hughes Experimental Test Area (BETA) field research facility to evaluate the feasibility of its use in an Expandable Tubular Technology application in the North Sea. The testing used a 9–7/8" Drill Out Steerable Ream While Drilling (DOSRWD) tool in conjunction with 6–1/2" pilot bits (both PDC and roller cone). Motor bent housing settings included 1.0°, 1.5°, 1.75° and 2.0° bends to evaluate directional and stability response. Surface speeds were varied from 0, 35, 50 and 75 rpm at each motor housing setting. Caliper logs including four and six-arm and ultrasonic borehole imaging (UBI) tools were used to characterize the borehole under all conditions. The analysis included directional tendencies, down hole vibration monitoring and borehole diameter, quality and degradation over time. The test results show the 9–7/8" DOSRWD system is capable of providing the high quality wellbore required for expandable tubular technology, ensuring the casing can be run, expanded and isolated across the formation.
Erskine Field HPHT Workover and Tubing Corrosion Failure Investigation
Authors: Mowat D. E. , Edgerton M. C. , Wade E. H. R. 
Published: December 2007

Abstract
The first workover of a UK North Sea ‘high pressure high temperature’ (HPHT) production well was successfully completed in August 1999. The workover in Texaco’s Erskine field resulted from failure of the duplex stainless steel production tubing in the through water zone. The workover benefited from detailed planning and peer reviews to identify necessary contingencies and technologies.
The tubing failure investigation is summarised. The failure was attributed to external chloride stress corrosion cracking in the calcium chloride packer fluid resulting from air ingress to the annulus.
Managing Drilling Knowledge for Improved Efficiency and Reduced Operational Risk
Authors: Bargach Saad , Martin Charles A. , Smith Reid G. 
Published: December 2007

Abstract
Drilling techniques and technology are changing rapidly as the industry continues to innovate in well construction. To keep pace with these advances, training must take a new direction, so that personnel are able to take advantage of new measurements and techniques in real time to improve drilling efficiency and reduce operational risk. In this dynamic and demanding environment, it is imperative that a drilling services organization improve its knowledge management— the ability to capture, share, and apply worldwide expertise— to consistently supply the best drilling solutions and practices. This is fundamental to achieving the vision of fully automated drilling systems operated remotely from the town office by a distributed, multidisciplinary team of experts.
Schlumberger started a knowledge management pilot project in early 1999. The initial focus was to build a Knowledge Hub—a Web portal for drilling personnel. Key sections are devoted to best practices and lessons learned. Practices are submitted by field engineers, validated by experts, captured in the knowledge base, and pushed to field crews for use worldwide. Today the ability to use in one part of the world what we have discovered in another is made possible by information technology tools and techniques. However, people are both the key to successful knowledge management and its most challenging element. Success depends on motivating people to share their knowledge and reuse that of others as part of their day-to-day jobs.
This paper describes the steps taken and the lessons learned along the way in establishing and institutionalizing knowledge management for Anadrill. It describes best-practice programs from companies inside and outside the petroleum industry and explains the program that was adopted.
Variations in Formation Temperature Due to Mature Field Production Impacts Drilling Performance
Authors: Sathuvalli U. B. , Suryanarayana P. V. , Erpelding P. 
Published: December 2007

Abstract
Optimization of offshore production facilities requires the placement of several wellbores in close proximity of each other. If the wells are spaced sufficiently close, diffusion of thermal energy between the wellbores has a pronounced effect on the undisturbed geothermal gradient of the formation. Such variations of the geothermal gradient have been observed while drilling new wells in mature offshore fields with wells that have been in production for six months or longer. When a new well is drilled in this section of the formation, higher geothermal temperatures are encountered at shallower depths. This can seriously impact the drilling, mud, cementing and casing programs.
Previous research concerning the heat transfer analysis of injection, production, and circulation is based on the thermal interaction of a single wellbore with the formation. These works typically use axisymmetric finite difference formulations of the wellbore heat transfer equations. Unfortunately, this approach is not adequate to analyze the effects of multiple wellbores. This paper bridges this gap with a technique to evaluate the thermal proximity effects of multiple wellbores. The method is based on the integral formulation of the heat conduction equation and it demonstrates the alteration of the undisturbed formation temperature profile. The results suggest that local geothermal temperatures in the vicinity of a producing field can be increased by several tens of degrees Fahrenheit.
A Pragmatic Approach to Injection Management of a Large Water Flood in The Largest Oil Field in Oman
Authors: Al-Mugheiry Mohammed Adil , Al-Barwany Amour , Al-Abry Yaaqub , Lozano Jose , Al-Lawati Mohammed 
Published: December 2007

Abstract
The Yibal Oil Field in the Shuaiba Formation in North Oman is the largest oil filed in Oman, contributing about 15% of the country’s production. The heavily faulted and fractured 70 km2 carbonate anticlinal structure was brought on stream in 1969 initially under depletion drive. This was followed by oil-leg injection directly into the oil column in 1972, then later by acquifer injection in 1980. Since then, more vertical infill drilling was carried out and almost all oil-leg injectors were converted to acquifer injectors with additional new injectors.
The associated oil-gain is found empirically to be about 10% to 15% of the injected water (typically, 1000 m3/d injected water can result in about 120 m3/d oil gain). However, the injected water volumes varies substantially from injector to injector through out the field, giving rise to uneven water injection distribution which ranges from 50 m3/d on the low side to about 4500 m3/d on the high side. Furthermore, the subsurface water movement exhibit various mechanisms such as bottom water rise, bottom water coning, fault plane channeling, fault plane line drive, radial flooding, fingering and edge water encroachment.
The intense horizontal drilling campaign in 1993 and improved higher off-take horizontal producers after simulation studies in 1997 resulted in direct impact on localised pressure drop and early water break-through. In addition, injected water was seen to have direct impact on the performance of some producers but not others combined with the difficulty of optimising the injectivity in some low-pressure areas due to surface or subsurface constraints. Thus, the need to develop a more pragmatic approach is innevitable.
This paper discusses the development of injection management methodology of the very wide Yibal Water flood. In particular, the discussion focuses on the improvements in the water injection scheme to sustain the field with more than 300 producing wells (horizontal and vertical) coupled with intense drilling campaign (about 50 wells per year) in the last four years. The paper will address the in-house developed tools in addition to the associated voidage and pressure mapping to manage the oil displacement in this complicated mature field. With the aid of these tools, areas with anomalies in the static pressure and voidage maps are identified and stability is re-established through combined off-take control, water shut-off, closing high water-cut or gas-oil-ratio wells, converting watered-out producers to injectors, optimising existing injectors or drilling new injectors.
Calibration of Permeability Derived from NMR Logs in Carbonate Reservoirs
Authors: Amabeoku Maclean O. , Funk James J. , Al-Dossary Saleh M. , Al-Ali Hussein A. 
Published: December 2007

Abstract
This paper discusses the calibration of nuclear magnetic resonance (NMR) logs to determine permeability distribution in carbonate reservoirs. The examples presented indicate the need for rigorous and integrated calibration to succeed in permeability estimation.
The promise of the NMR logging tool to deliver, among others, mineralogy independent total porosity and permeability makes it a tool of choice in formation evaluation. Significant savings in coring costs, particularly in horizontal wells, are possible with the NMR tool.
In sandstone reservoirs, NMR has worked remarkably well in the estimation of porosity, irreducible water saturation, producible fluids, and permeability. But the success rate is low in carbonate reservoirs, with respect to permeability. This can be attributed to the complexity of carbonate reservoirs and the lack of proper calibration of the logs with laboratory data or some measured reference.
The paper discusses calibration of NMR logs for permeability estimation, using laboratory NMR measurements, routine core permeability data, and formation test data. The calibrated models are then used to re-compute permeabilities in the logged intervals. The examples illustrate that reliable field-specific permeability modeling is possible when all relevant data are integrated into the calibration effort. The calibration effort also shows that it is not sufficient to adjust only the pre-factors in the SDR and Timur-Coates’ permeability models in order to make the NMR log data match the core data. The porosity exponent (m) and T2LM (or FFI/BVI) exponent (n) also require adjustments. The default values of m=4 and n=2 did not apply in most of the cases examined in this paper.
Case Study: Development of a Comprehensive Simulation Model for a Large Middle Eastern Carbonate in Kuwait and the Partitioned Neutral Zone, Kuwait
Authors: Sherman B. Blake , Al-Jadi Mohammad , Al-Najdi Ali , Al-Maraghi Easa , Nair C. V. G. 
Published: December 2007

Abstract
A reservoir management tool has been developed through the application of the latest in reservoir simulation technology for the Umm Gudair field - a large carbonate reservoir which is located in Kuwait and the Partitioned Neutral Zone. This paper will highlight the critical steps which were required for the development of an effective reservoir management tool for the field, such as maintaining the integrity of the geologic model through effective upscaling, thorough analysis of the engineering data, and the integration of the engineering data into the simulation model.
A complex geostatistical geologic model was built by a team of geoscientists using the latest in geoscience software and techniques. Because this geologic model was very detailed (144 layers, 10,000,000 cells), it was necessary to convert the geologic model into a reasonably sized simulation model through an upscaling process. In order to maintain the integrity of the fine-scale geologic model in a vertically upscaled simulation model, the engineering team applied flux-based upscaling techniques. These techniques allowed an appreciation for the effects of upscaling on the fluid flow, and generated a vertically upscaled model that effectively replicated the fine-scale fluid flow behavior. Two simulation models were generated - a coarse model containing 140,000 cells (to accelerate the history match process) and a 540,000 cell fine-scale model. The fine-scale model allowed for sufficient gridding detail for subsequent infill drilling studies. This paper discusses the efforts applied towards effectively converting the detailed geologic model to a simulation model through upscaling, capturing the engineering data in the simulation model, and the systematic approach applied in generating the history match. Finally, an overview of the quality of history match will be presented.
A Unique Approach to Enhancing Production from Depleted, Highly Laminated Sand Reservoirs Using a Combined Propellant/Perforating Technique
Authors: El-Bermawy H. , El-Assal H. 
Published: December 2007

Abstract
The primary objective in the design of a perforating program is to remove or minimize any impedance to the desired fluid movement from the reservoir to the cased wellbore. The possible damage that could occur from drilling-fluid contacting the formation is one of the significant problems that must be addressed in selecting the perforation technique. As drilling fluid enters the formation, it can deposit solid matter, cause clay swelling, and induce chemical precipitation, creating a damaged zone area around the wellbore. All of these resulting phenomena reduce the size of the pores available for fluid flow. In addition to the induced drilling fluid damage, the radial displacement of formation materials during the perforating event causes crushing and compacting of the area that immediately surrounds the perforation (better known as the crushed zone area), which will subsequently result in a reduced permeability envelope around the perforating tunnels.
Perforating the well in an underbalanced condition using super deep penetrating "premium" charges has proven to be an effective technique in removing near wellbore damage, as it allows the formation pressure to remove the damaged rock instantly. However, if the formation pressure is too low to move the damaged rock, permeability at the face of the perforation can be greatly reduced. In many wells, the damage can be so severe that only 25 percent of the perforations will produce.
This paper reviews the successful application of a combined propellant and perforating technique in depleted, highly laminated sand reservoirs. In the case histories discussed, applying this technique resulted in stimulated wellbore conditions that improved flow efficiency. The results from the pressure transient analysis are included and will verify the attained productivity improvements.
The paper also discusses the initial operational problems encountered in implementation of the propellant/perforating technique and the precautionary methods that were taken to address these scenarios.
A Multi-Purpose Reservoir Characterization Model
Authors: Shedid Shedid A. 
Published: December 2007

Abstract
The ultimate goal of petroleum engineering science is to maximize oil recovery at a minimum cost. This goal can be achieved by better understanding the heterogeneous nature of the reservoir rock. Reservoir characterization is considered the key to optimum oil exploration and exploitation.
The major goal of this research is to develop a multi-purpose reservoir characterization model capable of producing an effective reservoir description as well as an economical reservoir characterization. This model is developed to achieve the following purposes: (1) reservoir description of clean and shaly heterogeneous reservoirs using laboratory and/or in-situ (porosity and permeability) measurements, (2) robust and economical reservoir characterization of reservoir rock by using the concept of reservoir quality index in combination with various stress conditions during the extended life of an oil reservoir, and (3) investigate the effect of oil production (or stress) on reservoir characterization of clean and/or shaly heterogeneous reservoirs.
The newly proposed multi-purpose model incorporates petrophysical (porosity, permeability, and reservoir quality index), mechanical (effective stress, pore pressure, and average pore compressibility) properties and mechanics of fluid flow through porous media. Multiple cases are included to validate and illustrate the applications of the model in various situations considering different conditions of reservoir rock.
NMR Permeability Calibration Using a Non-Parametric Algorithm and Data from a Formation in Central Arabia
Authors: Al-Ajmi Fahad A. , Holditch Stephen A. 
Published: December 2007

Abstract
Nuclear Magnetic Resonance (NMR) logging provides a wealth of information to assist in the evaluation of a formation. NMR logs respond to the fluids in the pore space, and can be used to estimate lithology-independent values of effective porosity, pore-size distribution, bound and movable fluid saturation, and permeability on a foot by-foot basis.
Permeability models that include pore size distribution information are normally more accurate than models based on porosity information alone. Algorithms for estimating permeability from NMR measurements are based on the estimation of either a critical pore size or reducible water saturation. The algorithms that are based on empirical relationships will identify trends in permeability. However, to assure accuracy, the values of NMR permeability have to be calibrated with permeability data measured from cores. The typical NMR measurement is primarily sensitive to pore bodies, and is less sensitive to the size of pore throats that control permeability. Therefore, NMR calibration with core data is required for reconciling permeability from these two sources.
In this paper, optimal non-parametric transformation of variables with the Alternating Conditional Expectations (ACE) algorithm was used to calibrate NMR permeability to core permeability for a sandstone reservoir in Central Arabia. The use of the ACE algorithm significantly improved the correlation between the NMR and core permeability. Calibration of NMR permeability has improved the accuracy of the estimation of formation permeability using the NMR log. The permeability estimated using calibrated NMR esponse is positively correlated with core permeability with a correlation coefficient of 0.87.
Neural networks were also used to generate synthetic nuclear magnetic resonance effective porosity and permeability. A back-propagation neural network was used to associate and predict the relationship between conventional openhole logs, NMR permeability, and NMR effective porosity in control wells that have both NMR log and conventional openhole logs. The trained neural network was then used to generate synthetic NMR permeability and effective porosity to extend NMR curves to cover un-logged intervals and zones where borehole washouts affect the logging data. In addition, synthetic NMR porosity and permeability was generated for wells with no NMR logs. A Neural Network successfully predicted the NMR log response that would have occurred if NMR logs had been run, and created reliable synthetic NMR porosity and permeability.
NMR log porosity was compared eith porosity values from core, and calculated values of porosity from density log, neutron log, and sonic log data.
Stochastic Modeling of Porosity Distribution in a Multi-Zonal Carbonate Reservoir
Authors: Sahin A. , Al-Salem A. A. 
Published: December 2007

Abstract
Petrophysical variables, such as porosity and permeability in reservoir rocks, result from complex geological processes, and are characterized by considerable amounts of heterogeneity in their spatial distribution. The challenging task for geologists and engineers is to represent such heterogeneity in numerical reservoir models for flow simulation, leading to better predictions of reservoir performance.
Stochastic simulation techniques have commonly been adopted to construct numerical reservoir models in recent years. These techniques provide a range of equi-probable images or realizations of variable under consideration with a realistic level of heterogeneity. The Sequential Gaussian Simulation (SGS) is one of the popular conditional simulation techniques employed in reservoir characterization. The SGS algorithm provides a simulated value at any location by first determining the probability distribution at that location, and then drawing a number at random from this distribution.
The SGS technique was adopted to generate a three-dimensional, high-resolution reservoir model of porosity within the Upper Jurassic multi-zonal Arab-D carbonate reservoir in the Harmaliyah oil field, located in the Eastern Province of Saudi Arabia. The study was based on the well-log derived porosity measurements from 44 vertical wells. The generated models display the general pattern of the porosity distribution within the reservoir and provide the basic input for the flow simulation. As expected, the simulation model appears to have reproduced a realistic level of heterogeneity. Comparison of the histogram and statistical parameters of the input data with those of the simulated values reveals a close match in both the distribution patterns and the parameters.
A Unique Rigless Casing Leak Repair, Ghawar Field, Saudi Arabia
Authors: Styler James W. , Al-Suwailem Suliman S. , Akhnoukh Ramez L. , Leighton James R. 
Published: December 2007

Abstract
This paper describes the successful field application of a relatively new rigless technique to repair a casing leak in a saltwater disposal well in the Ghawar field in Saudi Arabia, the first installation of its kind in the Middle East. This unique repair method utilizes an electric-line-conveyed, non-metallic, composite sleeve composed of elastomers and thermo-setting resins reinforced with fibers. A description of the technology is presented, along with a brief history of its development, characteristics of the patch, and the installation procedure. The candidate selection process, candidate well history, and installation procedure for two patches are discussed, and economics are shown illustrating that this type of repair was economically superior to a rig workover.
A New Concept to Predict Sand Production from Extended Reach and Horizontal Wells
Authors: El-Sayed Abdel-Alim H. , Alsughayer Ali A. 
Published: December 2007

Abstract
The technology of extended reach and horizontal wells has recently progressed significantly. These wells have very few cost effective choices like slotted liners and openhole completion methods. Hole instability and sand production are the main problems of these completion techniques. To predict sand production an elastic plastic spherical cavity or cylindrical symmetry is assumed. Also, Mohr-Coulomb criterion is proposed for bore hole failure solution. These methods have limited applications and need actual cores to measure shear failure properties of rocks.
This paper introduces developed equations to predict sand production from extended reach and horizontal wells. A combination of Mohr Coulomb criterion and Von Mises criterion for cylindrical symmetry is developed and proposed to determine the hole instability and sand production. These equations allow calculating the sand free production rate for extended reach and horizontal wells depending on the uniaxial compressive strength of the rock. They also allow evaluating the effect of inclination angle, azimuth angle, well length and values and directions of in-situ stresses. Also, the equations can be applied easily in any area.