bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Dope-free Tubular Connection to SAGD and its Works
Authors: Tsuru Eiji , Tsukano Yasushi , Wakishima Ryohei 
Published: December 2007

Abstract
This study deals with the laboratory test results on the application of a dope-free connection (DFC) to a steam injection well, and the running results in the actual well.
A mechanical shock test, thermal shock test, and make-and-break (M&B) test were performed to evaluate the durability and the galling resistance of DFC with the new surface treatment. In addition, the effect of coating damage on the connection performance has been investigated. Under the predicted loading conditions, the connection performance was evaluated. The connections were used in steam assisted gravity drains (SAGD).
As the results of the test, it was found that DFC have enough galling resistance at an extremely low temperature and after a thermal shock was applied thereto. The galling resistance was not degraded in the case of a connection having a solid lubricant with coating damage. The joint strength and the gas tightness were maintained under repeated tensile and compressive loads at an elevated temperature. In the field usage, all connections were made-up without any thread compound grease (TCG), so that their running efficiency could be improved.
In conclusion, it is apparent from the results of the tests that DFC can endure field application. DFC not only eliminates the environmental problems caused by TCG, but also has some potential for saving running time.
Dieksand 2; an Extended Well Through Salt, Increases Production from an Environmentally Protected Field
Authors: Sudron Ken , Berners Heinz , Frank Ulrich , Sickinger Werner , Hadow Anthony , Klop Govert 
Published: December 2007

Abstract
The Mittelplate Field is being developed from the North Sea's only drilling artificial island and is Germany's largest producer. However, the tidal flats around the island became an environmentally protected nature reserve, which limited significant increases in production. This changed with the onset of extended reach drilling techniques, where drilling from shore proved to be a feasible option. The consortium of RWE-DEA AG (operator) and Wintershall AG, established an International Drilling Team and concentrated its engineering effort on the ERD well, but in particular the contingencies for the well due to the need to intersect a salt dome at high inclination and the limited amount of available geological information. It was these contingencies that influenced changes to a conventional ERD approach, by increasing top-hole sizes and casing specifications. This then had a knock-on affect to other techniques, such as achieving directional control and ensuring sufficient hole cleaning, whilst being hampered by known well-bore stability issues, such as the effects of salt tectonics. Known risks were reduced by upgrading the rig capabilities, incorporating an ERD customised profile, utilising friction reducing techniques, casing centralisation and cementing procedures. The well was finished in 159 days and reached 7727 m MD (TVD 2019 m), with a horizontal displacement of 6938m.
This paper outlines a case study of the well, through planning, execution and evaluation, that sets guidelines to engineer further ERD enhancements as the risks are reduced.
Borehole Stability Assessment Using Quantitative Risk Analysis
Authors: Ottesen S. , Zheng R. H. , McCann R. C. 
Published: December 2007

Abstract
A new wellbore stability analysis method based on Quantitative Risk Analysis (QRA) principles is described in this paper. Limit state functions that define the limit for failure (stuck pipe due to excessive breakout) and success (operationally tolerable magnitudes of breakout) are defined as functions of wellbore trajectory and geometry. Stochastic input data for the QRA procedure, which incorporate uncertainties in model input parameters, are generated by a fully three-dimensional wellbore stability model. Modeling results yield probability of success as a function of drilling fluid density. A field application of the method is presented to illustrate the viability of the analysis.
Hardbanding And Its Role in Deepwater Drilling
Authors: Mobley John G. 
Published: December 2007

Abstract
Hardbanding of drill pipe tool joints and other drilling equipment has been around since the late 1930's. Originally, hardbanding was applied primarily to protect the drill pipe and other tools from premature abrasive wear. Since that time, there have numerous changes in hardbanding and its application, but only within the last few years has new technology been introduced that allows hardbanding to protect the casing, the marine riser and the drill pipe at the same time.
Hardbanding is one of the most simple yet most misunderstood products being used on a drilling rig today. Along with the new technology being utilized to drill the highly deviated wells such as horizontal, ERD, or multi-directional, comes the problem of creating excessive downhole drag and torque. All of this drag and torque creates friction, which, in turn, creates wear on the drill string, the marine riser and the casing. Today, there are several types of wear resistant alloy hardbandings on the market. Most of them are designed to protect either the casing, riser or the drill string, but only one or two of them can sufficiently protect all of them at the same time.
Though the wear resistant alloy hardbanding technology has only been on the market for 6-8 years, it has gained increased popularity over conventional tungsten carbide hardbanding for several reasons. This technical paper will attempt to address these points in order to educate concerned parties as to which hardbanding to use in a particular situation.
The proper hardbanding with the right application can: Substantially increase the tool joint wear lifeGreatly reduce casing wear caused by the drill stringSubstantially reduce downhole drag and torqueReduce rig fuel consumptionAllow operators to run lighter weight and grade casing
Risk, Exploration and Hydrocarbon Property Evaluation: Comparison of Alternative Theories
Authors: Stauffer Thomas. R. 
Published: December 2007

Abstract
A method is presented for fully risking projects such as exploration ventures or the acquisition of undeveloped reserves. The expected value will in general overstate "value" because it does not reflect the uncertainty in the project, as measured by its variance or standard deviation. If the expected value is calculable, then the risk- adjusted value ("RAV") can also be calculated. The RAV depends additionally upon the size of the exploration budget compared with the project and also upon the "price of risk". That price is incorporated from the finance literature. The technique permits answering three related questions: 1) the risk-adjusted rate of return for a given project; 2) the risk-adjusted value of that project; or 3) the risk premium appropriate for a particular project given the size of the firm's exploration budget.
Conversion of Air Permeability to Liquid Permeabilities Extracts Huge Source of Information for Reservoir Studies
Authors: Macary Sameh M. 
Published: December 2007

Abstract
Permeability data form great part of data input in all of simulation studies. The importance of permeability data increases as the production life of oil fields becomes to later stages. However, the industry has a huge source of only air permeability measurements and a little number of liquid permeability values due to the relatively high cost of special core analysis. The present study suggests a correlation to convert air permeability into oil and brine permeabilities for Nubia "C" reservoir. Data of more than one hundred samples were gathered from 16 wells that are producing fore fields: October, Ramadan, East Tanka and Sidki. The data of other three fields: Hilal, Gebel El-Ziet, and Ras-Budran were used for to confirm the validity of the derived equations for oil and brine permeabilities. The comparison with the commonly used tables of Amoco conversion shows a higher accuracy and more consistent results over a wide range of permeability values. The conversion of air permeability to liquid permeabilities forms a cost-effective method for coring. The new correlation also introduces more feasible estimation in case of loose and poorly consolidated sands, or in case of the unavailability or invalidity of old cores to carry out oil and brine permeabilities. Further, the conversion formula offers the possibility to make a better use of the large amount of old air permeability data obtained through routine core analysis for the various further uses in geological modeling, reservoir simulation studies, reservoir surveillance/monitoring and production technological work.
Application of Geostatistical Modeling in an Integrated Reservoir Simulation Study of the Lower Bahariya Reservoir, Egypt
Authors: Aly Ahmed , Lee W. John , Datta-Gupta Akhil , Mowafi Khaled , Prida Manuel , Latif Mahmoud 
Published: December 2007

Abstract
This paper presents the application of geostatistical modeling to capture the reservoir heterogeneity in a Lower Bahariya reservoir, Western Desert, Egypt. "Conventional" geologic modeling in the highly heterogeneous Hayat Yasser field was not adequate to capture the heterogeneity and address the objectives of our study of the field. Previous studies were not successful in modeling this field due to the high level of heterogeneity. We used geostatistics to integrate well log, geologic, and core data to develop a 3D model that honors well data exactly and imposes spatial continuity relations derived from variography. Our modeling approach consisted of generating a three-dimensional porosity distribution using ordinary kriging and generating permeability realizations using a "cloud transform" that uses the porosity distribution in conjunction with the porosity/permeability scatter plot based on core data. The cloud transform technique uses concepts from conditional probability to preserve the inherent scatter in the porosity/permeability relationship.
In this paper we will present the geostatistical model selection, model validation (dynamic history matching) and model forecasting. We also present new techniques for quickly identifying the most promising areas for redevelopment in the reservoir prior to optimizing reservoir management strategies with the simulator.
Our conclusions and recommendations, based on the results of this study, will help improve future management and development of similar waterfloods in the region.
Enhancing Low Productivity Wells Using Special Gas Lift Design
Authors: Fotouh Mahmoud Aboul , Eissa Moh. , Al Gharabawy A. 
Published: December 2007

Abstract
Artificial lift using gas is considered the main source of life for most of Gupco's wells. Since employing gas lift technology in 1972, Gupco managed to improve total oil recovery and increase daily production rate in its operations. The conventional procedure for lifting well fluids by injecting compressed gas through gas lift valves using continuous gas flow design has realized significant production benefits over the years. But now due to the changing reservoir conditions, primarily declining reservoir pressure, an innovative approach to gas lift technology must be utilized to conserve available lift gas volumes while avoiding ineffective circulation of gas through the deep operating gas lift valves. Gupco overcame this problem by designing and implementing a system, which uses a combination design of continuous and intermittent gas lift procedures. The results of using these designs are very good, keeping wells on production when often time would be shut-in due to limitations in gas lift capacity. the gain is not only realized from maintaining wells on production, but also through redistribution of the additional volumes of high pressure gas. One of many success stories in Gupco is the case history of Morgan well M-41 where 1000 BOPD gain was realized while saving 1.5 MMSCFD of high pressure gas through the use of fluid operated and Pilo-Port valves rather than continuous injection. This new design is not common in operation around the world, but Gupco has effectively used this technique in improving production performance and is considered an industry leader. This paper will demonstrate all aspects of designing an installation, the advantages and disadvantages of this approach, and the detailed results of Gupco's success story. For this reason, we can now say that no gas is being wasted and we are getting maximum benefit from our gas lift investment.
A Challenge to Meet Environmental Law Number-4, A Comparative Evaluation Between Water-Treating Modified Systems and Other Available Oil - Water Separation Techniques
Authors: Kenawy F. A. , Kandil M. E. 
Published: December 2007

Abstract
Recent regulations, as per Environmental Law No. 4, prohibit disposing industrial wastes without necessary treatment to remove impurities and pollutants. In general, oily waste water treating equipment are categorized as 1) primary treatment equipment to protect the downstream facilities from surges and upset conditions, 2) secondary treatment equipment for bulk oil removal, or 3) tertiary treatment equipment to remove very fine oil particles. However, economics, size of equipment and simplicity of operation favored only the traditional oil-water separation facility to do the essential primary treatment. Therefore, in order to meet new environmental regulations while using only traditional oil-water separation facilities, it is necessary to improve its effectiveness for oil-water separation. A comparative evaluation study had been done to determine the feasibility of developing the currently used traditional systems including ballast ponds, API separator, CFP separator, outfall line, slop oil tanks, probes and possible waste-water re-injection.
Innovative Solutions in Developing Marginal Gas Fields East Shukeir Marine (ESMA) Gas Field
Authors: Shaheen Emam M. , Schultz Steve 
Published: December 2007

Abstract
The East Shukeir Marine (ESMA) gas field is located on the east side of the north bound shipping lane of the Gulf of Suez. It was part of the British Petroleum Company concession in 1985 when the ESMA-2 well was drilled, the analysis of open hole logs and DSTs concluded a limited reservoir and non-commercial reserves from the Kareem sandstone. Therefore, it was abandoned in July, 1985. In May, 1993 the concession was awarded to AMOCO.
The objective of this paper is "Demonstrating the ESMA reservoir development alternatives including various production schemes to achieve the highest shareholder value". Development plans included implementation of multidiscipline geological / engineering evaluations to justify reentry, acquisition of additional tests, test results analysis, reserve estimation and selecting the most economically attractive development scheme to bring the reservoir on production.
The critical question was "What is the size of the reservoir"?. Old DSTs indicated small area (45 acres), but without boundary effects. GUPCO's assessment using 3D seismic and pressure data reflected a larger area and inconclusive DST results. Re-entering the well to run an extended pressure test appeared to be the best technical solution. A risk analysis approach was used to conservatively bracket the potential ranges of drainage area. Results indicated a probability of economic success for reentry.
Extended DSTs for both oil and gas columns were performed after reentry. Results indicated a larger reservoir size (300+ acre area) and higher reserves (26 BCF and 1.5 MMBO) with production rates of 20 MMCFPD and 2000 BOPD.
Subsea technology was utilized to economically justify development of this one well marginal field. Application of a low cost subsea tree and 4.5" coiled tubing production line was utilized to capture the reserves. In November 1997, GUPCO put the well in production at 10 MMCFD and 2000 BCPD.
Prediction and Evaluation of the Impact of Reservoir Souring in North Kuwait, A Case Study
Authors: Al-Rasheedi Shamaa , Kalli Christopher , Thrasher David , Al-Qabandi Salman 
Published: December 2007

Abstract
Reservoir souring often occurs as a result of secondary recovery using water-flood. Until recently, the mechanisms of souring were poorly understood but it is now possible to quantify and profile the development of sour gas production.
The latest understanding of the mechanisms of reservoir souring have been used to model the souring potential of North Kuwait reservoirs, undertaken as part of a process of risk management in field development planning.
The Kuwait Oil Company has taken this one step further by interfacing the souring model to a proprietary, state-of-the-art, steady state process simulation package, as part of a wider process of integrated field development. Interfacing a sub-surface souring model to a process facilities compositional simulation has resulted in the ability to assess, with an unusual degree of confidence, the technical and economic effects of reservoir souring on facilities design and operation. This knowledge has been used for the preliminary assessment of options for controlling souring in the future.
To assure accuracy, the proprietary process simulation software thermodynamic generator, chosen for its ability to handle hydrogen sulphide, was independently validated by the thermodynamics section of BP Research Centre.
This paper reviews the basis of the reservoir-souring model and shows the results obtained in terms of sour gas profiles predicted over a period of time. It then goes on to show in more detail how these results were linked into a process simulation model which was constructed to emulate both existing and future facilities configurations.
The paper concludes by showing how the knowledge gained has allowed optimum decision making regarding the materials and equipment of the non-sour service facilities and the safety of operation. In addition, how this knowledge has been used for providing assurance and guidance for the planning of future production facilities.
The Development Process; Zubair Reservoir, Raudhatain Field
Authors: Dashti Hussain , Morrison Neville , Nemcsok Steve , Qazi Anees , Matar Bader 
Published: December 2007

Abstract
This paper describes the process adopted, and results achieved, to provide an interim field development plan for the Zubair reservoir. This is a major oil-producing horizon of the Raudhatain field in northern Kuwait. The multi-billion-bbl reservoir comprises four major producing sandstone units, each with different fluid and rock properties. The strategic intent set in 1995 required that the offtake essentially be doubled within the next 10 years through the implementation of a field waterflood development plan. Teams were established to collate the data and populate electronic data bases. The data from 21 new wells drilled after the liberation of Kuwait was integrated. A sedimentology study of the available core data was completed. A multi-disciplinary team was established in late 1996 to interpret the static and dynamic data and recommend the initial forward development strategy. Evaluation of the data, using classical analysis techniques, confirmed that a peripheral flood program could be implemented and provided an assessment of waterflood performance. Productivity and injectivity were estimated to provide a provisional assessment of wells needed. Ranged production profiles, required for planning, were generated quickly using analogue field data. Prioritization for water injection was established based on required offtake and dynamic performance. Recommendations for the locations of new development wells, incorporating the presence of tar mats and a gas cap, were made together with an adequate surveillance plan to assess the impact of the waterflood.
Modeling and Scale up Of A Heterogeneous Reservoir; Wara Sand, Greater Burgan Field
Authors: AL-Enezi Khalaf , Hsie James C 
Published: December 2007

Abstract
Reservoir studies of large fields with multiple pay zones and complex geology usually require considerable computer resources, manpower, and time. Conventional finite difference simulations offer the best technical justification provided sufficient grid resolution can be employed to define reservoir heterogeneity. Even though significant enhancements hardware has made simulation tasks of large models easier today, the 3-D simulation of full field fine grid models is rarely feasible, because of hardware limitations and extensive history matching requirements.
An approach based on detailed geostatistical characterization of the reservoir properties and a simplified flow calculation procedure was used to construct and scale up a 10.6 million cell geostatistical model to a 300,000 cell simulation model for the Wara reservoir in the Greater Burgan Field. Multiple geostatistical models were generated with different realizations and a representative model was selected based on probabilistic considerations. The fine grid model was scaled up by solving single phase flow equations for all x-z and y-z slices to characterize the reservoir flow parameters such as breakthrough time and fractional flow of oil. Non-uniform coarsening of the fine layers and areal grids was then made to match these flow parameters. The scale up of the permeability values is based on a homogenization procedure and the remaining static properties are calculated using pore volume weighting.
This paper demonstrates the merits of the scale up procedure to adequately capture the complex geology and heterogeneity of the reservoir and yet to retain critical flow characteristics in the coarsened model. It also discusses the limitations of the technique including the introduction of artificial discontinuities in the model and the procedure developed to incorporate over 100 faults, which need to be generated externally. The procedure can be employed to construct simulation models of giant Middle East reservoirs with adequate grid resolution and modest computer resources.
Identification of a High-Producing Ratawi Reservoir Extension in Wafra Field Using 3-D Seismic Data
Authors: Waite M. W. , Weston J. R. , Davis D. W. , Pearn C. J. 
Published: December 2007

Abstract
The Wafra Field is located in the Partitioned Neutral Zone between Kuwait and Saudi Arabia. The field produces oil from the Ratawi Oolite reservoir, which has been under production since 1956. Barriers to fluid movement have severely restricted aquifer support to the overlying carbonate grainstone reservoir, leading to production-induced pressure depletion and low recovery rates. Creative integration of 3-D seismic aspects, well log stratigraphy, and engineering analysis reveal an unexploited reservoir extension which is more open to aquifer support. Wells drilled along this extension are expected to yield higher initial production rates and longer sustained production. The model was used to drill two successful step-out wells that have increased field production by over 12,000 BOPD. Eight of ten additional wells have now been drilled as a follow-up to this success. This paper reviews the case history with a focus on the multidisciplinary integration that led to opportunity identification and exploitation.