bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shifting Paradigms—Underbalanced Drilling Technology Proves Highly Successful for Reservoir Evaluation and Drilling Performance Improvement in Kuwait
Authors: Vieira P. , Larroque F. , Al-Saleh A. M. , Ismael H. , Qutob H. H. , Chopty J. R. 
Published: December 2007

Abstract
The Shuaiba formation in the Raudhatain field is a highly fractured limestone reservoir. Conventional drilling technology in this formation usually results in a complete loss of drilling fluids to the formation. These losses cause severe formation damage which results in masking the evaluation of the potential for hydrocarbon production.
Underbalanced Drilling Technology was proposed as an alternative drilling method. The main objective of the UBD drilling application was to evaluate the potential of hydrocarbon in the Shuaiba formation while simultaneously eliminating fluid loss to the formation and improving drilling performance.
This well was the first well drilled underbalanced by KOC, a training program was prepared in order to familiarize the rig personal involved with the operation of the UBD equipment and procedures. The openhole section was drilled out of a 10 ¾" casing with an 8 ½" bit. A conventional mud pulse MWD/PWD/LWD tool with real-time annular pressure, temperature and gamma ray sensors were incorporated in the BHA. The use of MWD/PWD/LWD provided a means of monitoring the downhole underbalanced conditions and formation properties while drilling. The Shuaiba formation was successfully drilled underbalanced without any fluid loss during the drilling phase. The openhole section was drilled to a total depth (TD) of 8942 ft MD, with an openhole length of 242 ft.
Integrated efforts of KOC and service companies of various disciplines during planning and operation stages of the well led to the success of the project. No QHSE incidents were reported.
This paper highlights the key factors in the underbalanced drilling design phase, the operational challenges faced, and the results of the first well drilled in Kuwait using underbalanced drilling technology.
An Improved Model for the Liquid-Loading Process in Gas Wells
Authors: van Gool Frank , Currie Peter K. 
Published: December 2007

Abstract
This paper introduces an improved model for describing the liquid loading process in gas wells. The model is an extension of the model proposed by Dousi et al (2005).
The Dousi model handles the downhole inflow and outflow between the well and the reservoir in a simple manner. The new model improves this aspect, and makes more realistic and detailed assumptions with respect to the production and injection interval. Analysis using this new model improves understanding of the processes occurring downhole. Also it can be used to predict future behaviour of the well in a more realistic fashion. As in the Dousi model, two typical flowrates could be found, one at full production with all the fluids produced to the surface and one meta-stable rate where produced fluids are being re-injected into the reservoir. Field observations confirm the existence of two possible flowrates in many wells. The difference between the new model and the Dousi model is that changes in flow rates occur more slowly when liquid loading starts, reflecting the more realistic inflow performance assumptions.
With this model, liquid loading processes in the well can be better understood and predicted. This is important for optimisation of well performance and the economic assessment of the well and field.
Methane From Gas Hydrates Using Methanogens
Authors: Abraham Leo T. , Varma Esha N. 
Published: December 2007

Abstract
The growing need of energy and the depletion of the conventional resources i.e. the fossil fuels have led us to think seriously about the non conventional resources like solar, tidal, wind, waste energy, etc. Apart from these resources the science and technology is rather focusing more on gas hydrates. Natural Gas which is an important source of energy is being consumed about 85 trillion cubic feet per year. The current natural gas reserves show that they will last only for 60 years at this rate of consumption. But luckily the reserves of gas hydrates (natural gas) are enough so as to provide 100 percent of the present energy and will serve upto 2000 years, but we aren't able to extract them economically.
The idea of ‘EXTRACTION OF METHANE FROM GAS HYDRATES USING ANAEROBIC ARCHAE-BACTERIA’ may not only help in extracting methane from gas hydrates but also may convert water and carbon di oxide present in gas hydrates into methane. In this idea, I propose the use of anaerobic archaebacteria namely methanogenic archaebacteria, to convert carbon di oxide and water to methane. The above process is exothermic in nature that liberates heat, which can increase the temperature of water above its boiling point and cause gas hydrates to liberate methane. The characteristics of the anaerobic archaebacteria satisfy the conditions of existence of gas hydrates.
Thus, these bacteria may help in extracting methane from gas hydrates effectively and efficiently.
Productivity Tests: The Method for the Pre- and Post-Evaluation of Workover/Stimulation Jobs
Authors: Medina R. A. 
Published: December 2007

Abstract
At first, this paper presents the bases for a new approach of well testing focused on to determine well-reservoir properties from Flow-After-Flow tests. This approach opens the unprecedented real opportunity to use tubinghead pressure data as a powerful tool of analysis.
After that, the paper presents the evaluation of a field test to show the operational simplicity of the approach in evaluating a producing well either before or after a workover/stimulation job.
Lastly, it is proposed to make a further use of this new well testing approach in the industry to develop statistically: (a) The characteristic profile of "Initial-vs.-Final Skin Factor", for each kind of workover/stimulation job at each specific exploitation area; and (b) The characteristic profile of "Skin Factor through the Time", for each specific exploitation area. These profiles will let respectively, a more precise screening of the future stimulation candidates, and the forecast of the future stimulation jobs required in a zone to keep optimized its productivity.
Using Risk-Based Analysis To Identify Inspection Priorities
Authors: Belieu Stan , Kell Scott , Jehn Paul , Lowther David , Gillespie Deborah 
Published: December 2007

Abstract
Onsite inspection is the most expensive component of any regulatory oversight program, and agencies have been looking for ways to manage these programs cost-effectively while maintaining the same level of environmental protection. Developing the data analysis tools to monitor water quality and to assess available supplies has become critical to resource management. In response, the Ground Water Protection Council (GWPC) is expanding its Risk Based Data Management System (RBDMS) into source water quality protection, laboratory information management, produced water management, and water quantity assessment. RBDMS for Water tracks water and waste stream parameters and makes site-specific monitoring data available in a geographical information system (GIS) format. This paper discusses how RBDMS for Water is being customized by two regulatory agencies as a management and planning aid in refocusing their field inspection programs. These agencies are tasked with continuing to meet environmental protection goals in the face of stagnating funding and escalating real costs for these programs. The agencies: the Nebraska Oil and Gas Conservation Commission (NOGCC) and the Ohio Department of Natural Resources (ODNR).
Comparing Rigless Water-Cut Reduction Methods
Authors: Xue Yan , Yang Anping 
Published: December 2007

Abstract
High water cut is often the main factor affecting economical production of an oil well. There are mainly three technologies for reducing water cut: mechanical shutoff in production well, chemical treatment of production well, and injection well profile control. This investigation focuses on low cost rigless methods, comparing their potential effectiveness and economics based on existing applications and computer simulation.
There are mainly two types of rigless methods for water-cut reduction. One is mechanical method when each zone is isolated with packer and choke-sleeve during completion so that choke can be changed for each zone, including shutting the zone off completely, with a slick-line unit. Another is chemical method which depends on injecting agents into production well where the agents selectively reduce high permeability zone permeability or reduce water relative permeability without much damage to oil permeability. Chemical methods may also be used in fractured carbonate reservoir, though it is more difficult to be successful.
Our investigation shows that under suitable conditions, rigless water-cut reduction methods can be cost effective. Computer simulation can be used as a tool to support the selection of a suitable method and help predict the effectiveness of the plan.
Since there are many marginal wells and many of them are limited by high water cut, increased application of cost effective water-cut reduction technologies will improve the economics of these wells and prolong their life, increasing oil production.
Evaluation of the Potential for Gas and CO2 Leakage Along Wellbores
Authors: Watson Theresa L. , Watson T. L. , Bachu Stefan 
Published: December 2007

Abstract
Implementation of carbon dioxide storage in geological media requires a proper assessment of the risk of CO2 leakage from storage sites. Leakage pathways may exist through and along wellbores which may penetrate or be near to the storage site. One method of assessing the potential for CO2 leakage through wells is by mining databases that usually reside with regulatory agencies These agencies collect data concerning wellbore construction, oil and gas production, and other regulated issues for existing wells. The Alberta Energy and Utilities Board (EUB), the regulatory agency in Alberta, Canada, collects and stores information about more than 315,000 oil, gas and injection wells in the province of Alberta, Canada. The EUB also records well leakage at the surface as surface casing vent flow (SCVF) through wellbore annuli and gas migration (GM) outside casing, as reported by industry.
The evaluation of a leakage pathway through wellbore casing or annuli and what causes these wellbore leaks is a first step in determining what factors may contribute to wellbore leakage from CO2 storage sites. By utilizing available data, major factors which contribute to wellbore leakage were identified.
Data analysis shows that there is a correlation between these SCVF/GM and economic activity, technology changes, geographic location and regulatory changes regarding well completion and abandonment. Further analysis indicates a relationship between low annular cement top, external corrosion, casing failure and wellbore leakage (SCVF/GM). Other factors that could affect the presence of wellbore leakage, such as wellbore deviation, surface casing depth and wellbore density, were also investigated.
This paper presents the findings of the data analysis and a method to evaluate the potential for leakage along wells in an area where CO2 storage is intended. This information is useful not only for future operations of CO2 storage in geological media, but also for current operations relating to the exploration and production of hydrocarbons.
Technology Integration in the Caspian
Authors: Pannett Ian , Hodgson David 
Published: December 2007

Abstract
BP's Azerbaijan Strategic Performance Unit (AzSPU) has a very active and rich technology programme. It has been developed to meet the key challenges of operating within the Caspian region and to maximise business value. The key challenges facing the AzSPU that need to be addressed via the application of technology are: complex depletion plans, unconsolidated reservoirs, a difficult overburden to drill and an integrated development, gathering and export system. The key technology drivers are: reservoir management, new well delivery, drilling and completions performance, and facilities' operating efficiency.
To meet these challenges AzSPU has engaged in a number of key strategic technologies: advanced seismic, intelligent completions, zonal flow monitoring and control, and the FIELD OF THE FUTURE. These technologies collectively address the business challenges and will underpin superior business delivery.
Taken individually each of these technology areas has the potential to significantly impact the bottom line, but maximum benefit will only be realized when they are integrated along the value chain. The FIELD OF THE FUTURE programme in Azerbaijan aims to systematically integrate these technologies by optimising production and operating efficiency across this value chain, from the well's sand face 6km below the surface of the Caspian to the tanker 1760 km away in Ceyhan, Turkey.
AzSPU's the FIELD OF THE FUTURE programme has a detailed five-year plan and a longer term strategy. The value proposition for the first phase of this programme is to deliver 14mbpd by 2009. This paper outlines the FIELD OF THE FUTURE programme and highlights how it aims to integrate the whole value chain and maximise business value. This will include discussion on the key challenges and strategies involved, including technology development data analysis and interpretation, organisational capability and the integration of people, process and technology.
Underbalanced and Coiled-Tubing Drilling Technologies Successfully Applied in a Through-Tubing Horizontal Short-Radius Well in Hassi Messaoud Field, Algeria
Authors: Amor Bachir Ben , Ferhat Ali , Messas Rafik , Arnone Maurizio , Fudge Grayson , Stulberg Michael , Schoch Fritz , Qutob Hani , Chopty James 
Published: December 2007

Abstract
The Hassi Messaoud field (Figure 1), discovered in 1956, is the largest oil field in Algeria, covering about 2000 Km2 and currently including over 1000 Wells. The field is divided aerially into 25 zones that are separated from each other by low permeability barriers, usually faults. The Cambrian Reservoir is subdivided into four lithological zones designated from base to top as R3, R2, Ra and Ri. The Ra sub reservoir shows the best petrophysical properties with a maximum thickness of 150 m in the western part of the field. The Ra is farther subdivided into five sub zones: D1, ID, D2, D3, and D4 based on reservoir properties and depositional conditions.
Well F was the 6th re-entry well in the Sonatrach Coiled Tubing – Underbalanced Drilling campaign. A total of 363 m from KOP (303 m from landing point) were successfully drilled in a continuous underbalanced condition inside D1 and ID formations. As a result, the well productivity while drilling and while production test, the reservoir characterization and rate of penetration was significantly improved, compared with offset wells, due to the positive impacts of UBD operations.
The combination of Underbalanced and Coiled Tubing Drilling technologies has been proven to be a viable solution to successfully drill horizontal re-entry wells in mature fields where the reservoir pressure is adequate to induce underbalanced conditions using single phase or multiphase drilling fluid.
The experience in this field has validated the benefits of the combination of these technologies and has been attributed to the excellent balance between drilling cost and improved productivity. For example, the drilling cost in the short radius re-entry wells drilled with coiled tubing are highly reduced due to the elimination of pipe connection procedures, the increase in rate of penetration, the prevention of conventional drilling problems such as fluid circulation loses and related differential sticking events, the increase in the bit life and reduction in time and drilled distance to reach the profitable production level.
This paper describes the technical basis for the design and implementation of the Coiled Tubing Underbalanced Drilling project in Hassi Messaoud Field and highlights the operational key factors and challenges faced during this particular and successful application in Algeria.
Coil Tubing Deployed ESP in 5½ Inch Casing: Challenges in Designing Down
Authors: Mack John , Donnell Jimmy 
Published: December 2007

Abstract
In the short history of coil tubing deployed electrical submersible pumping (ESP) systems, 7 inch production casing has been the norm. However, recent applications with low flow volumes and high wax content require a smaller diameter production casing to maintain flow velocities capable of flushing the wax. The challenges of re-designing a complex coil tubing deployed inverted ESP were significant.
Inferring Interwell Connectivity from Well Bottomhole Pressure Fluctuations in Waterfloods
Authors: Dinh Anh , Tiab Djebbar 
Published: December 2007

Abstract
This paper presents a new procedure to determine inter-well connectivity in a reservoir based on fluctuations of bottomhole pressure of both injectors and producers in a waterflood. The method utilizes a constrained multivariate linear regression analysis to obtain information about permeability trends, channels and barriers.
Previous authors applied the same analysis to injection and production rates to infer connectivity between wells. However, in order to obtain good results, they applied various diffusivity filters to the flow rate data to account for the time lags and the attenuation. This was a tedious process that requires subjective judgment. Shut-in periods in the data, which were usually unavoidable when a large number of data points were used, created significant errors in the results and were often eliminated from the analysis.
This new method yielded better results compared to the results obtained when production data were used. Its advantages include: (1) No diffusivity filters needed for the analysis; (2) Minimal numbers of data points required to obtain good results; and (3) Flexible plan to collect data as all constraints can be controlled at the surface. The new procedure was tested using a numerical reservoir simulator. Thus, different cases were run on two fields, one with five injectors and four producers and the other with 25 injectors and 16 producers.
For a large waterflood system, multiple wells are present and most of them are active at the same time. In this case, pulse test or interference test between two wells are difficult to conduct since the signal can be distorted by other active wells in the reservoir. In the proposed method, interwell connectivity can be obtained quantitatively from multi-well pressure fluctuations without running interference tests.
Online Integrated Asset Models With Map-Based Visualization
Authors: Weber Michael J. , Vergari Alison Bondurant , Shippen Mack 
Published: December 2007

Abstract
BP North America Gas has completed the first stage of a ground-breaking R&D field trial in Arkoma, involving use of online integrated asset models and map-based visualization tools. This application called MAPS (Maximizing Asset Performance System) enables operators and engineers to geographically navigate and explore real-time operating data and model results across a large field, gaining new insights and interrelationships needed to optimize field and production performance.
In Arkoma and other assets, optimizing wells and facilities to achieve maximum performance requires sifting through volumes of data for hundreds of producing gas wells. MAPS is a new innovative means to geographically view and playback real-time data visually, enabling operators and engineers to navigate, explore, and discover information about the field and production. Through use of MAPS, online integrated asset models and real-time map-based visualization are now available to operations and engineering personnel from virtually any location, enabling better and faster identification of operating issues and opportunities for further action.
Integrity management issues are being addressed through use of MAPS and online models which are capable of providing insight and visibility into thousand miles of pipeline in terms of monitoring corrosion and erosion factors, as well as managing water, chemical usage or various location-based HSSE metrics. The MAPS tool is not limited to well or pipeline performance, but capable of locating and tracking field personnel and mobile equipment for managing field activities such as maintenance, drilling, equipment surveillance, or emergency evacuation. What began as a concept has now expanded into a robust visualization and modeling application which is expected to grow across other BP assets as part of FIELD OF THE FUTURE roadmap.
Laboratory Investigation of Influences of Initial Oil Saturation and Oil Viscosity on Oil Recovery by CO2 Miscible Flooding
Authors: Shedid Shedid A. , Zekri Abdulrazag Y. , Almehaideb Reyadh A. 
Published: December 2007

AbstractMiscible carbon dioxide flooding is an effective method for Enhanced Oil Recovery (EOR). The main objectives of this study are to investigate the influences of mobile oil saturation at the start of CO2 flooding and reservoir oil viscosity on oil recovery by CO2 miscible flooding. Actual fluid and rock samples used were obtained from a field under development in the U. A. ETo achieve the objectives of this study, six core-flooding experiments were performed using supercritical CO2 slug size equivalent to 0.15 hydrocarbon pore volume (HCPV) under simulated reservoir conditions of pressure and temperature. Five experiments were performed under different mobile oil saturations in the range of 32.74 % (i.e. after complete water flooding) to 79.43 % (with no water flooding). The sixth run was applied using heavier crude oil viscosity. All flooding experiments were carried out using actual core samples extracted from the field and flooded using actual reservoir fluids.The results indicated that the earlier the start of CO2 miscible flooding the higher the oil recovery. The start of CO2 flooding with the core saturated with oil at irreducible water saturation produced 98.61 % IOIP while flooding with CO2 after complete water flooding recovered 83.31 % IOIP. Furthermore, the increase of oil viscosity decreased the oil recovery by CO2 flooding. The injection of the same CO2 slug size produced 98.61 % IOIP for oil viscosity of 1.03 cp while the same application recovered only 86.11 % IOIP for heavier oil viscosity of 2.62 cp.The main conclusion drawn from this study is that while the application of CO2 flooding has successfully recovered more oil either after water flooding or as a secondary process, the application at initial oil saturation recovered the maximum oil recovery.
Case History: Acid Stimulation Devonian Horizontal Wells
Authors: Swain Michael , Nordstog Kim , Miller Howard , Weaver Bob , Metcalf Arthur S. 
Published: December 2007

Abstract
In the Arbol De Nada Field in Ector and Winkler Counties of Texas, there are 29 producing wells in the Devonian. Recently several horizontal wellbores have been added to the field. Five of these are newly drilled and have been completed with uncemented liners and openhole packers for isolation. Between each of these packers is a sliding sleeve to facilitate stimulation. The Devonian has a limestone, dolomite and chert composition which makes acid fracturing the method of choice for stimulation.
Given the open annular space between the packers, zonal coverage is dependent upon rate and fluid choices. Presented are the results of stimulation work on these horizontal wells. Included is a discussion on rates and fluids chosen. Production responses are also presented in comparison to the vertical completions.