bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Laboratory Feasibility Study of Dilute Surfactant Injection for the Yibal Field, Oman
Authors: Babadagli T. , Al-Bemani A. , Boukadi F. , Al-Maamari R. 
Published: December 2007

AbstractThe Yibal field, the largest oil field in Oman, comprises 15 % of the oil production of the country. The field has had a high ultimate recovery factor and in order to maintain the current recovery trend, different management strategies have been sought. One of the options is the injection of dilute surfactant in addition to the current waterflooding scheme.The cores from the chalky Shuaiba formation were saturated with brine and oilflooded to restore the initial reservoir condition after cleaning process. Nineteen samples were exposed to waterflooding succeeded by dilute surfactant injection. Eight samples were directly exposed to dilute surfactant injection. The reason behind this scheme is the fact that some parts of the reservoir under study were totally watered out, due to field waterflooding, and some parts are still untouched. In addition to these experiments, nine capillary (static) imbibition experiments were also carried out. This is with the intension of covering fractured zones, where recovery by capillary imbibition during injection is a possibility. The investigation considered testing of twelve different surfactants available in the market at different concentrations. Five of these surfactants were nonionic, two cationic, four anionic, and one mixture of anionic and non-ionic. The selection of the optimum concentration values for each surfactant was based on the measured IFT values at different concentrations.The results were evaluated in terms of the final oil recovery. The average waterflooding recovery was found to be 75.1 % of OOIP (out of 19 experiments) whereas surfactant injection (modified waterflooding) yielded an average of 69.9 % of OOIP (out of 8 experiments). This indicates that the surfactant injection is not preferable and not recommended over waterflooding for the untouched portion of the reservoir where the rock matrix dominates the flow (unfractured portions). An additional recovery by surfactant solution injection succeeding waterflooding, however, was obtained and found to be varying between 0 and 7.4 % of OOIP. The surfactant injection is, therefore, recommendable in the pre-waterflooded unfractured zones as long as the proper surfactant type is selected. Half of the surfactant solutions yielded higher and faster capillary imbibition recovery than brine. For the untouched fractured zones of the chalky reservoir, it is, therefore, more effective and recommendable to start the injection with surfactant addition rather than waterflooding alone. Surfactant types and concentrations yielding the best performances were identified and listed in this paper.
Comparative Economics Of Deep Drilling In Anadarko Basin
Authors: Rietman N.D. , Rumph K.D. 
Published: December 2007

Abstract
In the Anadarko Basin, well development costs increase exponentially with depth. Average porosities for both sandstone and carbonate reservoirs decrease with depth in a predictable manner. Normal pressure and temperature gradients and a general porosity-water saturation relationship can be used to establish gas in place for reservoir rock at various depths. Recoveries can be calculated using typical permeability versus porosity data.
A base case with 10 feet of net sandstone pay at a depth of 10,000 feet was used for comparative purposes. A 0.15 probability of this case yields an expected discounted cash flow rate of return of 15%. At depths of 15,000, 20,000 and 25,000 feet, sandstone pay thicknesses of 29, 89 and 297 feet are required to match the base case in terms of volume of gas in place per dollar spent. If recovery rates are considered, these thicknesses must be increased to 34, 128 and 670 feet respectively, to maintain a 15% rate of return. Similar relationships are indicated for carbonate reservoirs.

Introduction
The purpose of this paper was to compare economic for wells in the Anadarko Basin for depths varying from 10,000 to 25,000 feet. Because of the low incidence ooil occurrence below 10,000 feet, only gas wells were considered. For comparative purposes, economics for a base case gas well at a depth of 10,000 feet were run. Economics were then calculated for gas wells at depths of 15,000, 20,000 and 25,000 feet. The following data were used:constant gas price, gas gravity and operating expenseexisting Anadarko Basin data correlating porosity with depthnormal temperature and pressure gradientsgeneral variations in water saturation and permeability with porosity
Pay thicknesses were varied to maintain constant economics at depths of 10,000 to 25,000 feet. Economics were considered both from the standpoint of maintaining a constant cost per Mcf of gas in place and also a constant cost per discounted Mcf of gas recovered. For this paper, the term "discounted Mcf" refers to the gas volume which is derived from projecting production rates with a deliverability model projecting production rates with a deliverability model and discounting those predicted volumes of gas with 15% present value factors. This approach considers both recovery efficiency and the present value concept of money.

BASE CASE
For this case, the following data were used:10,000 ft depth10 ft sandstone pay400 acre drainage area0.65 gas gravity (no condensate)4340 psia original pressure207 degrees F reservoir temperature12% porosity27% water saturation0.5 md permeability-4 skin factor215 psia pipeline pressure$475,000 producing well cost (1/3 equipment;2/3 intangibles)$380,000 dry hole cost$2.07/Mcf gas price$20/day operating expense50% tax rate (federal income, production and ad valorem taxes)3/16 royalty20 year double declining balance depreciation
Horizontal Wells Pressure Build Up Analysis in Orinoco Heavy Oil Belt
Authors: Briceno M. , Summers L. E. , Quijada O. J. 
Published: December 2007

AbstractThe innovative application of horizontal drilling technology has made the Petrozuata development project in Venezuela a great success. Petrozuata is the first of four strategic associations implementing an integrated development in the Faja trend, which contains 1.36 trillion barrels of oil in place and is one of the world’s largest heavy oil accumulations. The joint venture of Petroleos de Venezuela, S.A. (PDVSA) and Conoco, Inc., drilled 101 single lateral and 140 multi-lateral horizontal wells in the Zuata Field from 1998 to 2001 as a means of delivering production rates of up to 3000 BOPD per well from reservoir sands of 8° to 10° API oil.Well test interpretation and analysis techniques have been applied to both single and multi-lateral horizontal wells. This paper summarizes the methodology developed to analyze pressure build up (PBU) tests in the single lateral horizontal wells and recent experiences with the application of state of art PBU analysis techniques in the Zuata field wells.Because of the geological complexity of the fluvial-deltaic reservoir sands and the peculiar transient pressure behavior, it was necessary to integrate analytical techniques that identified the various flow regimes with numerical analysis that further quantified the analytic interpretation. The integrated approach allowed for improvements in the conventional analytical interpretation and provided a basis of incorporating refinements in the reservoir description when combined with geological and petrophysical data and interpretation.
Automatic Determination of Well Placement Subject to Geostatistical and Economic Constraints
Authors: Norrena Karl P. , Deutsch Clayton V. 
Published: December 2007

Abstract
Optimal well placement is a complex problem that requires detailed models of the reservoir structure/geometry and the petrophysical properties such as facies, porosity, permeability, and fluid saturation. The reservoir development team attempts to integrate all of these aspects when devising a well plan for optimal reservoir exploitation. Ideally the well locations would be selected with the assistance of a flow simulator; however, this is impractical due to time and CPU requirements. This paper presents a technique for selecting optimal well locations for fine-tuning with a flow simulator. The technique constructs the well placement problem as an optimization problem to be solved with simulated annealing. The global objective function consists of multiple component objective functions. Each component represents a desirable feature or constraint in the problem. Optimality is defined as the best balance among the component objectives. The format of the technique is flexible and can incorporate 3-D geostatistical models of uncertainty and multiple constraints. The proposed method iteratively refines initial well locations and trajectories until the global objective is maximized. Several examples are shown. Optimal well placement in a steam assisted gravity drainage context is illustrated.
Modelling a Double Piston Pump
Authors: Becerra Oscar , Gamboa Jose , Kenyery Frank 
Published: December 2007

Abstract
The idea of using serial arrangements of sucker rod pumps to efficiently produce heavy oil wells with high gas to oil ratio has been analyzed in Venezuela since 1996. However, models to calculate the dimensions of the required plungers have not been presented in previous literature. An analytical model is presented in this work, based on the geometry of the pumps and the properties of the fluids to be handled. This model was validated using experimental data acquired in a reduced scale test bench, where machine oil and air were used as pumped fluids. A good performance of the dynamic model predicting dina-graphic card was observed. It was also found that the static model was useful for determining the application window of any arrangement. At the same time, a poor performance of the flow model through valves was observed due to the simplifications assumed on the model of the process.
Quantifying the Impact of Grid Size, Upscaling, and Streamline Simulation in the Risk Analysis Applied to Petroleum Field Development
Authors: Ligero Eliana L. , Maschio Célio , Schiozer Denis J. 
Published: December 2007

AbstractGeological uncertainties usually have a strong impact on the decisions applied to petroleum field development. Methodologies to quantify the impact of uncertainties are still not well established due to the amount of variables that have to be considered. The complete analysis usually depends on geological, economic and technological uncertainties that have different degrees of impact in the recovery process and may affect the decision process in different levels depending on the problem, reservoir characteristics, recovery mechanism and stage of field development.The objective of this paper is to evaluate the importance of the numerical simulation process in a risk analysis applied to a petroleum field development. The use of fast estimation of recovery factor can be used in the exploration risk analysis but, during appraisal and development phases, more reliable techniques must be used to predict the reservoir performance in order to quantify accurately the impact of uncertainties and evaluate risk.One of the drawbacks of the use of numerical simulations can be the required computational effort. Therefore, this paper evaluates the impact of using different degrees of accuracy in the procedure, calculating risk with different options of grid size, number of attributes, levels of uncertainties and also comparing the results with streamline simulation which is used also for very fine models.The proposed procedure is tested in the SPE 10th Comparative Solution and a comparison is presented for several different options. Finally some conclusions are taken based on accuracy, required computational effort, model scale, comparing also results from simulation through finite difference model and streamline.
New Well Design Using Expandable Screen Reduces Rig Time and Improves Deep Water Oil Production in Brazil
Authors: Rosa Fabio S. N. , Bianco Luis C. B. , Barata Paulo A. 
Published: December 2007

Abstract
The Marlim Sul Field, located in Campos Basin, southeast Brazil, is the one of the largest oil fields in the country. The water depth ranges from 1000 to 1900 meters and has been developed by horizontal wells with potential productivity up to 5000 m3/d. Due to the presence of unconsolidated sandstones, sand control is mandatory and open-hole gravel-pack has been used to avoid sand production. The regular casing program consist of a 30" conductor casing, a 13 3/8" surface casing, a 9 5/8" production casing and a 5 1/2 " base pipe screen gravel packed in the 8 1/2" horizontal section. The application of new technologies such as rotary steerable tool, expandable screens and synthetic oil base drilling and completion fluids allowed a new well design, eliminating one phase in the well. This new design used a 30" conductor casing, 10 ¾" production casing and a combination of conventional 7" liner and a 5 ½" expandable screens inside of the 8 1/2"well. The liner and the expandable screens are deployed in one trip. After screen expansion, a cementing job is performed through a stage collar in order to isolate the formation above the pay zone. Besides the overall cost reduction, an increment in well productivity is expected. Simulations showed that compared to 5 1/2" base pipe screen, the increased internal diameter achieved by the expandable screens, increases the PI and establishes a better production distribution along the horizontal section1. Therefore, a delay in the water production is expected.
This paper is focused in the criteria used for the new well design and the operational procedures used for well construction.
Zero Discharge System: An Innovative Drilling Rig Design to Protect the Environment in Lake Maracaibo
Authors: Suarez D. , Segovia G. J. , Valera R. E. , Nava L. A. 
Published: December 2007

Abstract
In 1999 the operator entered into a 10-yr contract with an oilfield services company to drill and work over wells in mature areas of Maracaibo Lake. In this alliance the operator will share risks and involve the services company in the operations performance through an incentive-penalty scheme with the objective of reducing operation times and costs, protecting the environment, maximizing reserves recovery and introducing technologies to achieve the desired goals.
The engineers pooled their knowledge and expertise to build multipurpose green rigs designed for well construction and work over on Lake Maracaibo environment. Likewise, each rig has a sophisticated treatment system to recycle wastewater into water suitable for industrial use. The document presents how this system can avoid pollution and the wastes are sent onshore to be taken to a zone designated for their final disposal or recycling and the sophisticated system that these rigs have to operate with zero discharge of any pollutants in Lake Maracaibo.
Methodology for Engineering Analysis for Deepwater Drilling in the North Atlantic with a Dynamically Positioned Drillship
Authors: Reyna Erick , Kuchner Keith 
Published: December 2007

Abstract
A number of engineering and operational considerations are addressed during the planning stage of a deepwater operation. Most Deepwater operations occur in benign environments such as the Gulf of Mexico and West Africa. The subject well was drilled in the United Kingdom on the Western edge of the North Atlantic in an area of potentially severe metocean conditions. This paper summarizes the comprehensive analysis that was performed for a deepwater drilling operation utilizing a dynamically positioned (DP) drillship in this area. This analysis more accurately defined the guidelines required to operate the rig safely under anticipated Northern Atlantic sea state conditions.
Planning Fit for Purpose Solutions with Roller Technology - the Value of Applied e-valuation
Authors: Fraser Scott D. , Rennie Mike , Mason Colin J. 
Published: December 2007

Abstract
Extended-reach drilling and completion operations are often at the limits of current technology. Roller tool technology has frequently been used to overcome onerous torque and drag challenges associated with drilling and completing high angle wells. These tools significantly reduce mechanical friction, and as described in this paper, enable completion operations to match the reach obtained by current drilling practices.
Significantly, roller tool technology is currently being used to drill and complete a series of 16 horizontal wells from a semi-submersible rig in the North Sea. A record 15,360ft high angle well with a horizontal reach of over 13,300ft and true vertical depth (TVD) of only 2,900ft has recently been drilled and completed. This well sets a new benchmark for shallow extended-reach wells in the industry.
The appropriate application of roller tool technology is instrumental to cost-effective drilling and completion of high departure wells now, and in the future. In order to further progress this technology and to ensure that it is used in the most appropriate way, demands that quality data be captured from each operation and interpreted in a consistent and correct manner.
Offline Subsea Wellhead MODU Operations Provide Significant Time Savings
Authors: Kenda William P. , Allen Timothy J. , Herbel Ryan R. 
Published: December 2007

Abstract
BP has combined existing technology with appropriate SIMOPS (Simultaneous Operations) planning to safely achieve significant cost reductions in deepwater field development by running several subsea wellhead components offline of drilling activities. This was achieved by utilizing conventional subsea wellhead tools that have been adapted for use in open water with the support of a subsea winch located in the moonpool on a mobile offshore drilling unit (MODU) and an ROV. The traditional method of deploying and installing the equipment using drill pipe requires that this work be done in the critical path of operations, using the rotary table. This takes more time because running drill pipe takes significantly longer than deploying wire rope off a winch.
Offline operations included deployment of wellhead corrosion caps, gasket seal prep protectors, and two different stack-up height measurement tools, installation of lockdown hangers, guidelineless re-entry assemblies (GRA), brushing the wellhead bore, and injecting corrosion inhibitor. The ROV system capability has been key in removing these operations from rig critical path by facilitating the operation, installation and retrieval of the tools.
BP's Holstein Drilling Team challenged itself to generate best in class performances by installing the lockdown hangers and GRAs, using offline subsea wellhead tools and ROV technology. This offline operational approach was successfully used on BP's Gulf of Mexico Horn Mountain project. The Holstein Team refined the concept and redesigned the tools from lessons learned, allowing the scope of the work to be increased to 16 wells. Removal of the operations from the critical path resulted in an estimated savings of 31 days of rig time for the project. These repetitive operations on multiple wells, in a field development scenario, resulted in significant cost reduction of $9.75 million, while meeting all safety expectations.
The First Underbalanced Multilateral Well Branches Drilled in Brazil, a Field Case History
Authors: Lage Antonio C. V. M. , Sotomayor Gabriel P. , Vargas Angela C. , da Silva Paulo R. C. , Lira Humberto L. , Filho Paulo Silva 
Published: December 2007

AbstractThe present work describes aspects related to planning and execution of six multilateral horizontal branches drilled underbalanced (UB) in Carmopolis field, which is located in Sergipe/Alagoas basin, in Brazil's Northeast Region. This field, discovered in 1963, is the country's largest onshore oil accumulation and has its production zones, which consist basically of sandstones and conglomerates, depleted at about 700 m deep (TVD).As the targeted formations are consolidated, UB drilling did not bring any special concern in terms of wellbore collapse. In order to achieve the required bottomhole pressure nitrogen was mixed with a synthetic based mud (SBM) after flowing down through the annular space between the 9 5/8″ and 7″ casings and passing through a 1″ aperture in the 7″ casing. After that, the two-phase mixture went up through the annulus between the 7″ casing and the jointed pipe drill string. This concentric casing approach for injecting gas made possible the use of conventional MWD, but it brought some concerns, which are addressed and discussed, about the maintenance of the UB condition while operating.The first multilateral well UB drilled in Brazil is an example of the combination of different technologies as multilateral level 2 well design, UB condition and medium radius directional system. In addition, it also involved four different parties where the operating company worked together with two service companies and a drilling contractor to build a team and achieve operational success.
Development of a System for Diagnostic-While-Drilling (DWD)
Authors: Finger J. T. , Mansure A. J. , Knudsen S. D. , Jacobson R. D. 
Published: December 2007

Abstract
This paper describes development of a prototype Diagnostic-While-Drilling (DWD) system that provides high-speed, realtime downhole data while drilling. The system has been demonstrated in both laboratory and field drilling. Project background, benefits, major technical challenges, and field test planning and results are described.
Telemetry Drill Pipe: Enabling Technology for the Downhole Internet
Authors: Jellison Michael J. , Hall David R. , Howard Darrell C. , Hall H. Tracy , Long Roy C. , Chandler R. Brett , Pixton David S. 
Published: December 2007

Abstract
Drill pipe capable of transmitting high-bandwidth data from downhole sensors and surface control signals back to those sensors has been developed and successfully tested. The system incorporates a high-speed data cable that runs the length of each joint and downhole tool. The cable terminates at induction coils that are installed in protecting grooves machined in the secondary torque shoulders of double-shoulder tool joints at each end of the pipe. The coils are recessed in ferrite troughs that focus the magnetic field. The system is virtually transparent to standard rig procedures and offers robust, reliable operation.
The paper provides background data on prior work relating to telemetry drill pipe and contrasts the results of these efforts with the new system. The new system has successfully demonstrated data transmission rates of up to 2,000,000 bits/sec. Current mud pulse telemetry is limited to 8 to 10 bits/sec. Electromagnetic technology provides data rates of up to 100 bits/sec, but suffers from hole depth and formation related electric impedance limitations.
Full realization of system benefits requires further development of additional drill stem components with highspeed telemetry capabilities including HWDP, collars, jars and top drive subs. A top drive sub that incorporates the telemetry design has been successfully manufactured and tested and is described in the paper. Development efforts relating to other drill stem components are also detailed. The system has been tested in a laboratory environment and in test wells. Results of these tests along with plans for field-testing in actual drilling environments are presented.
Telemetry drill pipe can improve well and field productivity by providing more complete, real-time logging information and reduce drilling time and costs and enhance well control by providing real-time downhole drilling data and early kick detection.