bluuebunny/crossref_metadata_2025_split huggingface dataset:
Intelligent Recompletion Eliminates the Need for Additional Well
Authors: Lie Ole Henrik , Wallace Wayne 
Published: December 2007

Abstract
The wells in the Gullfaks field, operated by Statoil in offshore Norway, produce from several reservoirs, with the largest reserves being found in the Brent, Cook and Statfjord sands. Only one well in the field, Well C-29, produced from the Lunde formation.
Although Well C-29 intersected the Statfjord formation, commingled production could not be considered since differing pressure regimes, the productivity index, and expected watercuts ruled out this possibility. When the well economics from Lunde formation production became unfeasible, the original plan had been to plug and recomplete the well in another zone. Rather than follow the originally planned well scenario, an innovative technology that introduced a surface-controlled downhole choke system was suggested and subsequently used. This paper will discuss the recompletion of this well.
The new system had the capability to provide two important benefits. It would not only allow commingled production, not possible before, but would save a dedicated Statfjord well slot. The system, incorporating a number of zonal isolation packers and adjustable downhole chokes, each independently controlled from surface, would provide this well with the means of selective or simultaneous production.
The recompletion operations were to be divided into two major parts with the first using hydraulic workover (HWO) to accomplish the through-tubing zonal isolation and tubing-conveyed perforating (TCP) operations. The second operational phase was to be performed with a drilling rig, which would pull the existing completion and run the new completion, employing the zonal-isolation control system.
The completion was successfully installed, and the well is currently a commingled producer with all downhole systems functioning and communicating as planned. The installation proved to be economically favorable, and production plans for the area have been revised to take full advantage of the enhanced reservoir data that has been generated from the well due to the new "intelligent well" completion technology. Of particular significance is the fact that this is the world's first recompletion in which intelligent well technology has been used.
First Multilateral Application in a Deep Devonic Gas Field in the North of Argentina
Authors: Piasco Luis E. , Eguia Hugo V. , Roca Eduardo Perez 
Published: December 2007

Abstract
The purpose of the paper is to show the first experience in drilling a multilateral well in a depleted, highly-fractured Devonian reservoir in the North of Argentina (Salta province). The well was drilled and a dual completion device was run successfully to produce one million cubic meter of gas from each one of the two branches of the well. The total cost of the well was $18.1 MM compared to the $14.5 MM for a single vertical well in the same field. The KOP for the first branch was at 2815 m with a length of 1001-m (TMD). For the second one the KOP was 2763 m with a length of 951 m (TMD). The well was completed as a MLT level 3 with the possibility to be changed to a level 5 in the future. A new whipstock technology was applied in the country for the first time. The paper will show casing design, application of the RWD technology, drilling operation sequence, Whipstock operations (difficulties and how they have been solved) time and total operation costs. Another interesting topic to be explained is the different behavior experimented in each branch regarding the fluid loss in the depleted zone. The results to be shown are the cost savings due to the replacement of two wells by one in a highly difficult logistic zone, the relatively new technology applied successfully in a deep highly deviated MLT well, and the improvement in casing design due to the RWD application in a highly tectonic zone
Unintentional Compensator Lockup Risks, Consequences and Measures
Authors: Storegjerde D. , Sandbu P. , Kvernmo E. , Simmenes R. 
Published: December 2007

Abstract
Unintentional compensator lockup is a well known and industry wide problem, which has received recent attention, following several serious incidents in the North Sea. As similar systems are used worldwide, there is no reason to believe that the failures seen in the North Sea are isolated occurrences. There may however, be some correlation with the severe sea conditions experienced, especially during the winter months, but most geographical areas have such seasons. When using the crown compensator during normal drilling operations, the consequences of an unintentional lockup may be limited. When the rig is rigidly attached to the seabed in connection with e.g. drill stem testing or sub sea completions or interventions, the consequences can be much worse. This paper briefly examines the consequences of three such incidents and details some of the risk and consequence reducing measures implemented to combat the problem. Risk reducing measures includes the modifications made to the existing compensator, while consequence reducing measures discuss the development of new technology to provide redundancy. The objective is to raise the awareness of the possible consequences of a compensator failure and hopefully stimulate increased focus on this critical system.
The Application of Rotary Closed-Loop Drilling Technology to Meet the Challenges of Complex Wellbore Trajectories in the Janice Field
Authors: Edmondson John , Abbott Chris , Dalton Clive , Johnstone John 
Published: December 2007

Abstract
It is usual for initial development wells on marginal fields to follow a conservative drilling programme using conventional technology with known drilling performance. In the case of the Janice Field situated in block 30/17a of the UK North Sea it became apparent, following field appraisal, that to effectively exploit the reservoir it was necessary to drill complex 3D well trajectories. Such wells would require significant directional work with large associated costs. Specific challenges included high torque and drag profiles, slow rates of penetration, limitations of conventional directional drilling techniques, tight target tolerances and the requirement for effective reservoir navigation.
After careful consideration, the operator, Kerr-McGee North Sea U.K. Limited determined that the application of Rotary Closed Loop Steerable (RCLS) technology was part of the appropriate technical and economic solution for the drilling of these wells.
This paper describes how the combination of RCLS and conventional drilling technology was used to achieve the field development objectives. This provided a unique opportunity to make a direct comparison between RCLS and conventional steerable technology on similar 3D complex well trajectories. Specifically, key performance factors were measured enabling quantitative and qualitative statements to be made of drilling performance with the two technologies. The experience gained provides an insight to where it is appropriate to use this new technology and demonstrates the applications for which this technology can provide significant technical and economic advantages.
Underbalanced Drilling in High-Loss Formation Achieved Great Success – A Field Case Study
Authors: Luo Shiying , Hong Ruyu , Meng Yingfeng , Zhang Liehui , Li Yun , Qin Changqing 
Published: December 2007

Abstract
This paper describes the execution of Well Xian-2 using underbalanced drilling technique. At first, new equipment was specially designed for the well, including a liquid/gas separator and a new manifold. Then, the design of wellhead, drillstring, casing, gas injection program, bit selection, well completion and base drilling fluid used in the well are discussed. Besides, operation of UBD in the well is summarized in the paper. Finally, it is concluded that: UBD technique can minimize loss of drilling fluid into formation and increase productivity. As a whole it makes money, though the drilling cost is increased compared with conventional drilling. Simulation for underbalanced drilling plays an important role in optimization of the drilling parameters, which is dictated by actual reservoir inflow performance and well conditions.
A New and Practical Method for Fracture Design and Optimization
Authors: Richardson Michael 
Published: December 2007

Abstract
There is a very long and continuously expanding list of considerations in the process of designing and optimizing fracture stimulation treatments. As a result, there exists today an equally long and varied list of recommended design and optimization procedures for fracture stimulation. However, for each of these methods, the key parameters that ultimately govern the production response after fracture stimulation remain effective fracture length and effective fracture conductivity. This paper presents a simple and easily applied fracture stimulation design and optimization procedure that centers on these two vital parameters. The analysis includes adjustments to fracture conductivity for closure pressure, temperature, embedment, gel damage, non-Darcy turbulent flow, and non-Darcy multi-phase flow. A methodology is presented that optimizes fracture stimulation design for any reservoir type and can be readily applied by practicing stimulation engineers.
Aqueous Polymers for Treating Clays in Oil and Gas
Authors: McLaughlin H.C. , Elphingstone E.A. , Hall Bobby 
Published: December 2007

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

Abstract
Protection of water sensitive formations Protection of water sensitive formations is a serious problem in the production of hydrocarbons. Water sensitivity is usually the result of fines migrating which is triggered by introduction of foreign water. The migrating fines tend to lodge in constrictions in the formation flow channels where they severely reduce production. Water sensitivity can be simple clay swelling, but fines migration causes more permanent damage. However, swelling of clays in fines is an important mechanism for dislodging fines and starting the migration.
The sodium clays are the important form of swelling or dispersing clays. Since sodium ion is easily replaced by others a successful method of helping to prevent swelling and migration is to treat the clays with potassium, calcium, ammonium or hydrogen ions. With these ions the clays are relatively inactive if not quiescent. However, this is temporary protection because sodium ion from formation water protection because sodium ion from formation water quickly counter replaces the non-swelling ions and the clay returns to the swelling or dispersing form.
A new series of certain polymer materials has proved to be effective in treating water sensitive formations. These polymers adsorb tenaciously to surfaces of clay minerals and other formation fines, helping to prevent clays from swelling and fines from migrating should foreign water be introduced into the formation. The polymers win easily in competition with other simple ions (such as ammonium, calcium or potassium) for being deposited on clay surfaces. Furthermore, once deposited on clay surfaces, the polymers are not easily replaced by exchange with other ions. Subsequent acidizing treatments cause no detectable harm to the ability of the polymers to protect the clay. protect the clay. Laboratory test data with sand packs and cores are presented and annotated. The encouraging results of these tests are supported by the results of fracturing treatments, acidizing treatments, and other operations, which are tabulated and discussed.

Introduction
Many oil and/or gas producing formations contain clays, clay minerals, silica fines, and other fines.
Downhole Video: A Cost/Benefit Analysis
Authors: Tague J. R. , Hollman G. F. 
Published: December 2007

Abstract
In the past few years, downhole video has emerged as a viable and cost-effective means for analyzing various wellbore problems. Despite this, numerous misconceptions concerning the cost, application, and complexity remain. In an effort to provide insight into the proper application and selection of this unique tool, the results of over 30 downhole video logs conducted by Chevron in the West Coalinga field will be presented and discussed. Examples will include images obtained of damaged liners, casing holes, and corrosion problems, as well as their application to remedial well work. Other examples will include images of the in-situ producing environment, in particular, the ability of downhole video to image fluid entry and the impact of various wellbore plugging agents including scale and organic precipitation. Finally, the total cost of running a video log and the steps necessary to prepare a well will be compared to more traditional means of logging. Overall, this paper should provide valuable insight for anyone considering the use of downhole video.
Did Checkerboard Steamflooding Work at Kern River?
Authors: Harris Dan E. , Sanford Steven J. 
Published: December 2007

Abstract
A checkerboard-style (Fig. 1) steamflood was initiated on the "MC2" lease of the Kern River field in 1991. We recently evaluated the project to see how it fared and to identify development opportunities.
Even though we overinjected steam, the checkerboard steamflood was mostly unsuccessful because steam did not migrate across pattern boundaries. We suspect that heat was escaping via slotted liners.
We found unswept oil from time-lapse temperature-observation-well (TOW) data and from pulsed-neutron-capture (PNC) logs. We recompleted injectors to steamflood previously unsteamed zones. Downward-conductive heating also enabled more oil to be produced. The oil production quickly increased as a result of this work.
More Than 12 Years of Experience with a Successful Conformance-Control Polymer Gel Technology
Authors: Sydansk R.D. , Southwell G.P. 
Published: December 2007

Abstract
In this paper, we discuss and describe our extensive exper-ience with the widely applied and quite successful Cr(III)-carboxylate/acrylamide-polymer (CC/AP) gel technology for use in oilfield conformance-control, sweep-improvement, and fluid-shutoff treatments, along with briefly reviewing the gel technology's development. Chromic triacetate is the often-preferred chemical crosslinking agent used in conjunction with this polymer-gel technology. The CC/AP gel technology, which was conceived in late 1984, is characterized as having a robust gel chemistry and as being highly insensitive to petroleum reservoir environments and interferences. This gel technology has been employed in over 1,400 conformance-control treatments worldwide. Highlights of illustrative field applications and results involving the CC/AP conformance-control gel technology are presented. An overview of what a decade-plus of experience in developing and applying the CC/AP gel technology has taught us is discussed. This includes discussion of: classifying and distinguishing conformance problems and treatments, attributes of good candidate wells and well patterns for gel conformance-control treatments, requirements that must be met in candidate wells and well patterns in order to achieve success, gel treatment elements that must be successfully implemented in order to achieve success, guidelines where conformance polymer-gel treatments are most successfully applied, risks and pitfalls of gel conformance treatments, and quality control issues.

Introduction
The development and application of effective conformance-control treatments have been, until somewhat recently, elusive goals within the oil industry. Broadly speaking, conformance-control treatments include both treatments to improve volumetric sweep efficiency during oil-recovery flooding operations and treatments to reduce excessive and unproductive co-production with oil of such fluids as water and gas. That is, the co-production of other fluids that compete with the production of oil. Conformance-control treatments have at times been referred to, in an overly narrow fashion, as profile-modification treatments. Polymer gels of conformance treatments act as permeability-reducing agents and, as such, act as blocking and plugging agents. The gels of such treatments operate by reducing the fluid-flow capacity within the treated portion of the reservoir.
Experimental Study of Surfactant Alkaline Steam Flood Through Vertical Wells
Authors: Shedid Ali Shedid , El Abbas A. Abbas 
Published: December 2007

Abstract
Continued research and field application of steam flooding have confirmed an early conclusion that the process is a powerful method for recovering heavy and intermediate gravity crude oils. This experimental study investigates the feasibility of using low concentrated solution of alkaline or surfactant as an additive to steam flooding for water flooded reservoirs. This research is also designed to search for optimization the process of steam flood through recovering additional oil via using a steam with low concentration of alkaline-surfactant mixture. This process is designed as surfactant alkaline steam flood. To achieve these goals, four flow experiments are conducted as follows: (1) conventional steam flood (SF) (2) surfactant steam flood (SSF) (3) alkaline steam flood (ASF) and (4) low concentrated surfactant alkaline steam flood (SASF).
The results of this study confirmed using steam flooding for a substantial improvement of oil recovery. Using low concentrated alkaline into steam drive recovered additional oil than conventional steam flooding. Mixing steam flooding with surfactant improved oil recovery than either conventional steam drive or alkaline steam flood. The proposed technique of surfactant alkaline steam flood (SASF) significantly enhanced oil recovery.
A comparison of the obtained results of the four undertaken experiments results in two major conclusions, which are (1) addition of 3 % wt. of surfactant or alkaline into steam drive improves its performance and consequently recovers additional oil than conventional steam flood, and (2) using low concentrated surfactant alkaline (1.5% wt. for both) into steam flood produces the highest oil recovery.
The results of this study have validated the proposed technique of surfactant alkaline steam flooding. Furthermore, this technique is expected to have a significant impact to attain potential oil recovery, if applied in current projects of conventional steam flood and/or water flooded reservoirs.
Confinement of Wastes Injected Below Thawed Permafrost: A 12 Year Update from the North Slope of Alaska
Authors: Weingarten Jean S. , Bill Michael L. , Andrews Donald E. 
Published: December 2007

Abstract
The main North Slope Class I industrial waste disposal facility has injected 12 million barrels into a permeable formation just beneath the permafrost at 2000 feet. Initial concerns about fluid confinement were addressed by extensive field testing. This testing, coupled with the absence of underground sources of drinking water, allowed injection pressures to be authorized above the fracture gradient - an unusual operating condition.
Re-permitting the facility in 1999 required an evaluation of permafrost thermal response to the injection of warm fluids and determination of potential impacts on waste confinement. This was accomplished using temperature logging after a one week shut-in period and by thermal modeling. At issue was whether the temperature log profiles could be explained by conductive heat transfer or whether they indicated upward fluid movement out of the injection zone. The evaluation was accomplished by coupling a radial thermal model with a onedimensional vertical conduction model. This combination could better predict the temperature profile adjacent to the injection interval because vertical heat transfer is dominant just above the storage reservoir.
Very good agreement was obtained between field measurements and the model results, indicating there was no fluid moving upward through the confining zone. With this "history match" as a basis, the model was used to predict future temperature changes and thaw bulb growth throughout the permafrost interval.
Interwell Seismic for Reservoir Characterization and Monitoring
Authors: Justice J. H. , Woerpel J. C. , Watts G. P. , Waddell W. 
Published: December 2007

Abstract
The U.S. Department of Energy Class II Oil Program was designed to encourage evaluation of new technologies which might improve production in marginal shallow-shelf carbonate reservoirs. One of the largest of the approved programs has been underway in the Welch field, located in the Permian Basin of west Texas for several years. In the first phase of the program, a wide variety of data was acquired, including 3-D seismic, log and core data, and one of the largest interwell seismic baseline programs to be carried out at that time. The purpose of the interwell seismic program was twofold. First, there was interest in using the baseline survey data itself to evaluate its use for reservoir description and characterization (simulation). The second objective was to acquire subsequent monitor surveys, after CO2 injection had begun, in order to map the actual location and movement of the CO2 through the reservoir, as the program progressed.
The first phase of the project is now complete, and the first round of monitor surveys has been acquired in the second phase of the program. Based on comparison of the baseline surveys and the first monitor surveys, and using prior petrophysical work as a basis for interpretation of the results, the injected CO2 appears to be exhibiting a strongly preferential flow direction oriented toward the east/southeast.
Using Alternative Sources of Oilwell Cement
Authors: Hibbeler Jeff , Rae Phil , Gilmore Todd , Weber Lawrence 
Published: December 2007

Abstract
A survey of cement manufacturers in the Asia Pacific Region revealed that only five companies produce a certified API Class G cement. Because of this, certain countries have been forced to import cement and in many cases ship it great distances. In some situations, API Class G cement can cost three times more than local construction cement. While the authors believe that the API Monogram is an excellent benchmark for oilwell cement, the question is – is it necessary to preclude good local cements from use simply because they are not certified. After all, the key issues for oilwell cement are predictability and performance, not certification In the absence of local API Class G cement, the authors propose two ways to use local cement in oilwell applications. First, work with existing construction cement companies to develop cements that consistently meet specifications of the desired API Class and use it in the field. Second, when and where it is applicable, use construction cement for oilwell cementing. The authors are implementing both techniques successfully in parts of South East Asia.
This paper presents historical and technical background as well as laboratory data to support the use of local cements as an alternative to imported API Class G cement. Also, presented are several case studies on the use of local cement in oilwell applications as a means to save drilling costs.
Reducing Well Costs by Optimizing Drilling Including Hard/Abrasive Igneous Rock Section Offshore Vietnam
Authors: Salleh Sahabudin , Eckstrom Darren 
Published: December 2007

Abstract
Bit optimization played a key role in a recent drilling program by an oil company in its Pilot Production Drilling campaign in the Ruby Field Offshore Vietnam. Advancements in roller-cone and PDC bit technology improved performance significantly. These advancements enabled the operator to save time on the 10 well plus 2-workover project and come in under budget. This paper documents the time savings and the development of the crucial roller cone bit technology.