bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ultraslim Rotary-Steerable System Gives Greater Reservoir Access in Saudi Arabia
Authors: Dhaher Karam , Chia Christopher R. , Al-Amri Khalifah , Bargawi Riyadh Ahmad 
Published: December 2007

Abstract
This paper describes the successful introduction of ultraslim rotary steerable system (US-RSS) drilling in Saudi Arabia. A case study is presented where a 2167ft power water injector redrill lateral was successfully drilled in the reservoir using an US-RSS on 2 3/8"drillpipe in conjunction with ultraslim logging-while-drilling tools, which were used for concurrent high accuracy geosteering. The existing casing design required that the sidetrack had to exit the liner in the reservoir section, since sidetracking higher up was not an option because of the risk of exposing problematic formations and pressurized zones. A number of challenges had to be overcome, including engineering design for sufficient weight transfer to be able to drill and good bit selection, since it would have been impossible to drill the planned section with a motor or conventional drilling assembly.
Each stage of the job was carefully planned in detail and all stakeholders were briefed and contributed to the plan to ensure that all objectives – both drilling and well placement, could be met. The US-RSS was run in hole to drill the lateral, which was drilled with a 3 7/8" bit and concurrently opened up to 4¼". The US-RSS tool performed as planned and produced an overall rate of penetration (ROP) of 28ft per hour in a single run during the geosteering operation. All well objectives were achieved, and the system clearly demonstrated a robust technical solution to the problem.
The US-RSS will enable greater reservoir access, especially in the redevelopment drilling application, and when used in conjunction with ultraslim LWD tools, can also be used to place the well in the best position for optimal additional production. Recovery rates from the field are now expected to be enhanced as a result of this technology, and without the need for drilling further new wells.
An Efficient Response Surface Approach for the Optimization of ASP Flooding Processes: ASP Pilot Project LL-03 Reservoir
Authors: Zerpa Luis E. , Queipo Nestor V. , Pintos Salvador , Tillero Edwin , Alter David 
Published: December 2007

AbstractThe EOR method so called alkaline-surfactant-polymer (ASP) flooding has proved to be effective in reducing the oil residual saturation in laboratory experiments and field projects through the reduction of interfacial tension and mobility ratio between oil and water phases.Two issues are critical for a successful ASP flooding project: i) addressing issues related to laboratory design such as chemicals selection and concentrations, in order to obtain an optimal ASP formulation, and ii) establishing an optimal injection scheme for the field scale flooding process, that will maximize a given performance measure (e.g., oil recovery efficiency or displacement efficiency), considering a heterogeneous and multiphase petroleum reservoir. This paper presents an efficient solution approach for the latter issue.The approach is based on the construction of quadratic response surface models (surrogates) of reservoir simulator outputs and three-level D-optimal design of experiments. It allows to effectively and efficiently establish the optimum ASP injection scheme, and was applied to determine the optimal values of injection rates, slug size and initial date for injection of an off-shore ASP pilot project being developed by PDVSA at La Salina Field, LL-03 Miocene reservoir on the eastern coast of Maracaibo Lake, Venezuela. The optimum injection scheme resulted in substantial savings in chemicals used when compared to the laboratory design.
Improved Well and Reservoir Management in Horizontal Wells Using Swelling Elastomers
Authors: Mahrooqi Majid Abdullah , Hinai Ghaliba , Marketz Franz 
Published: December 2007

Abstract
Petroleum Development Oman (PDO) is producing substantial amounts of unwanted water or gas from most of its oil fields. To increase recovery from maturing reservoirs, PDO is developing the capability to detect and shut-off unwanted water and gas. Swelling elastomers have been deployed to segment horizontal wells in combination with surveillance and shut-off technologies. In beam pump wells dual wellheads have enabled logging while pumping.
A key element to achieve improved oil recovery through well and reservoir management in a horizontal well is segmenting the well into different flow units. Swelling Elastomers (SE) are being deployed to enable segmentation. SE tool provides zonal isolation through the swelling of the elastomers when contacting produced water in the wellbore.
In clastic reservoirs the completion philosophy has been changed from drilling minimum functionality wells to wells with closed-annulus completions that allow for surveillance and interventions. Surveillance is done in the drilling phase with under-balanced drilling and other open hole logging measurements. In the work over phase unwanted flow segments have been detected by logging while pumping coupled with greater integration of available reservoir data. Mechanical segment shut-off methods have been used.
To date PDO has segmented more than 100 horizontal wells with swelling elastomers. In more than 20 wells suspected water producing feature were isolated at the initial completion stage and the rest were segmented based on reservoir flow unit characterization. After having proved that SE is delivering value in initial water shut off, the strategy is to prove a viable surveillance technique to identify water entry point in horizontal wells, and to develop several reliable water shut off (WSO) techniques depending on which segment's to be closed and if reversibility is required. To date more than one million barrels of oil have been realized as a result of the initial isolations as well as subsequent water shut offs. This paper is a continuation to the work presented in SPE paper number 91665 and will present case histories of the delivery and management of wells with swelling elastomer in clastic reservoirs in Oman
Implementation of a Shock and Vibration Mitigation Process: Achieving Real-Time Solutions and Savings
Authors: Akinniranye Goke , Weber Amanda , Elsweisy Hesham , Palacio Julio , Poedjono Benny , Goobie Roger 
Published: December 2007

Abstract
Worldwide the costs associated with the exploration and production of oil have increased at a nearly exponential rate. This sharp rise in daily costs has also led to a new urgency from operators to find more reliable and efficient ways of doing business.
Shock and vibration (S&V) are the leading cause of failure for measurements-while-drilling (MWD) and rotary steerable systems (RSS) today. These failures have a major impact on operators and service companies, costing millions of dollars in repairs and hours of rig time.
A wide variety of service companies now offer lateral, axial, and transverse shock measurements, as well as downhole revolution per minute (RPM) readings to better understand downhole dynamics. These measurements in the best of cases offer a reactive method of drilling, and at the worst provide no help in solving the problem or preventing damages to the bottom hole assembly (BHA).
For shock and vibration measurements to be effective, operators and service companies need to work together to create a comprehensive process to include each phase of drilling: planning, execution, and evaluation. A shock and vibration standard combined with increased client awareness and education have allowed a new level of success to be set at the rig site. Now, shock and vibration issues at the rig can be flagged in real-time and monitored remotely from an operations support center (OSC). This communication structure, coupled with pre-job planning and modeling and the capture of post run lessons learned, can be used to offer solutions when problems arise; thus preventing damage to the BHA, reducing rig non productive time (NPT), and improving the rate of penetration (ROP).
Using Decision Analysis to Solve Real Option Valuation Problems: Building a Generalized Approach
Authors: Hahn W. J. , Dyer J. , Brandao L. E. 
Published: December 2007

Abstract
There are several different methodologies for finding the value of assets or projects that have both underlying uncertainty and the managerial flexibility to optimize decision making. This has led to questions about the differences between approaches to these so-called real option valuation problems; the assumptions, mechanics, and applicability of the various methods for different problems.
In this paper, we show that traditional decision analysis methods can provide an intuitive generalized approach to valuing real options. The first characteristic of our approach is a departure from the binomial lattice framework with replicating portfolios that is typically implemented in the discrete-time approach in the Finance literature to a binomial decision tree with risk-neutral probabilities. This gives an equivalent but more intuitive framework for approximating the uncertainty associated with the changes in the value of a project over time. The second characteristic is a methodology for combining uncertainties for a project into a single underlying uncertain variable; the present value of the project itself. This approach provides greater flexibility in modeling of real problems, including the ability to include multiple underlying uncertainties and multiple options with complex payoff characteristics.
We apply this method to an example acquisition valuation problem, showing the specification of project uncertainties, cash flows, and decisions, and demonstrate how solutions can be obtained with commercially available decision tree software.
Economic Capital Optimization for Oil Firms
Authors: Hightower Lee 
Published: December 2007

Abstract
"Economic Capital Optimization" (ECO) provides a comprehensive methodology to improve a firm’s expected long-term growth while reducing its risk. This framework adapts and extends proven economic capital methodologies developed in the financial services industry to address both the similar and unique financial issues facing oil companies.
Economic capital is the capital a firm must maintain to sustain long-term growth by covering short-term and long-term needs or losses. For sustainable growth, a firm must have the capital to support the operations that create economic value, despite anticipated and unforeseen shortfalls in cash flow or changes in business cycles. Insufficient economic capital can disrupt a firm’s operations, destroying value and eventually leading to potential default. Overcapitalization or poor allocation of economic capital can lead to corporate returns and growth that fail to meet investors’ expectations.
Optimizing economic capital requires properly aligning a firm’s capital structure, strategies, capital allocation process and risk management practices to maximize long-term growth. ECO provides a practical framework for examining the interdependencies among these components and for understanding how each impacts the long-term success of the organization.
This paper discusses the concepts behind ECO and its practical application in the oil industry. This paper also will demonstrate how an oil company can improve its expected long-term growth by applying the ECO framework to more effectively allocate economic capital among business units or projects, to adjust its economic capital to meet long-term strategic needs, and to better manage its risks.
Overcoming Environmental Challenges Using Innovative Approach of Dynamic Underbalance Perforating
Authors: Baxter Dennis , McCausland Harold , Wells Brian , Mishra Vinay K. , Behrman Larry 
Published: December 2007

Abstract
This paper discusses the implementation of dynamic underbalance perforating in a subsea development, which helped address environmental concerns related to flaring during perforating. Use of a new perforating system implemented on recently completed wells has resulted in a significant reduction in flaring while maximizing underbalance during gun detonation. The elimination of flaring has also simplified perforating operations, resulting in significant time savings.
The Terra Nova offshore field is located 350 km off the East Coast of Canada. It is a subsea development producing from a multi layered, highly faulted oil reservoir to a Floating, Production, Storage and Offloading vessel (FPSO). The development plan utilizes high productivity producer-injector pairs in the individual fault blocks to optimize recovery. Initially, standard practice was to perforate wells using multiple runs of wireline conveyed guns, up to 6 runs per well. In order to maximize completion efficiency the wells were perforated in an underbalance condition. The underbalance was generated by flowing back and flaring the well at the Mobile Offshore Drilling Unit (MODU) during each wireline run. The net results were multiple flowbacks per well, with diminishing underbalance for each successive perforating run due to flare rate limitations. The multiple flowbacks increased the risk for environmental incidents due to unintentional releases while flaring. Alternative gun deployment methods had been considered but deemed undesirable due to sump limitations and potential for formation damage.
In order to minimize flaring an innovative perforating technique was implemented. This technique generates dynamic underbalance during gun detonation, mitigating the need to flare the well to create underbalance. Fast pressure gauges were run on wells perforated using this method and the data confirmed that dynamic underbalance was achieved. Successful implementation of the dynamic underbalance system has resulted in elimination of flaring related to perforating operations, and has significantly reduced the potential for unintentional environmental releases.
Locating and Repairing Casing Leaks With Tubing in Place—Ultrasonic Logging and Pressure-Activated Sealant Methods
Authors: Johns J. E. , Cary D. N. , Dethlefs J. C. , Ellis B. C. , McConnell M. L. , Schwartz G. L. 
Published: December 2007

Abstract
When operators are faced with issues involving casing leaks, a typical course of action is to pull the tubing and make efforts to identify and locate the source of the leak by logging or other mechanical means. If the leak source can be successfully located, a mechanical method is generally employed to patch the leaking casing. This methodology is time consuming and expensive.
Locating casing leaks with the tubing in place using conventional logging techniques has historically been difficult. Where some tools, such as temperature tools, may provide an indication of an anomaly in annuli, the data may be subjective or the leak may be too small to measure. When active, a leak will produce a spectrum of sonic frequencies that may be either audible, ultrasonic or both. Ultrasonic energy will pass through steel but travels relatively short distances. A tool developed around these principles has been successful in accurately locating casing leaks behind tubing.
Pressure-activated sealants have been used for a number of years to cure a wide variety of leaks in casing, tubing, control lines, and well heads as well as micro-annulus leaks in cement. For the purpose of repairing a casing leak behind tubing, the liquid sealant may be pumped into the annulus and displaced to the leak site. The liquid sealant will not polymerize until it is exposed to the differential pressure through the leak site. Knowing the leak rate, pressure and precise location of the leak aids in the selection of the sealant formulation and deployment method. This helps to reduce overall repair cost as well as increase the probability of a successful repair.
This paper will describe the ultrasonic method of leak detection and the method of curing leaks with pressure activated sealant with tubing in place. Case histories will be presented where these methods were employed to repair casing leaks without removing the tubing.
How to Evaluate the Effect of Mud Cake on Cement Bond Quality of Second Interface?
Authors: Ma Yong , Cui Maorong , Guo Xiaoyang , Shi Qing , Li Li 
Published: December 2007

Abstract
A set of HPHT core filter press and a special manmade core have been designed to simulate the bond quality of second interface of cement job, i.e. the bond status between borehole wall rock contains mud cake and slurry, mud cake has formed on the rock at HPHT conditions. The filter press consists of three parts: heating jacket, HPHT cauldron and core holder, and the center of special manmade core has been drilled a disconnected hole as filtration outlet of drilling fluid. The drilling fluid only can filtrate from the outer wall of the special core to that of inner wall and form mud cake at the outer wall when carrying out filtration experiment of drilling fluid, so this bond status is in agreement with downhole condition. Slurry bond mold has been combined with HPHT core filter press, a novel method for evaluating the bond quality of second interface of cementing has been developed, and the method has been used to measure the shear bond strength between manmade core and slurry.
In order to verify the rationality of the method, it has been applied to evaluate the effects of three drilling fluids on the second interface after mud cake formed on the special core. High flow rate washing before cementing has been simulated to wash manmade core after HPHT filtration experiment. The study shows that the novel method is simple, scientific and rational, better simulates the bond status of cement-formation interface; the mud cake has a pronounced affect on the shear bond strength; this method has high applied value, and develops a good foundation for studying the effect of drilling fluids upon the bond strength of second interface quantitatively; high flow rate washing before cementing is helpful for improving the bond quality of cement to formation.
Drilling Cost Optimization in Iranian Khangiran Gas Field
Authors: Bahari A. , Seyed A. Baradaran 
Published: December 2007

Abstract
Cost optimization, is a procedure, which its final goal is to reduce the cost by making the interfering parameters to the optimum level. In drilling operation, a large amount of saving in time and money will be achieved, by reducing the drilling time, since; some of the costs are time-dependent. Drilling time is reduced by increasing the rate of penetration. Rate of penetration is affected by many parameters such as hydraulics, weight on bit, rotary speed, bit type, mud properties, formation characteristics, etc. In this research, nine wells from Khangiran gas field were selected and by comparing drilling parameters in these wells, a primary optimization by comparison has been performed. Then, secondary optimization using mathematical techniques was applied to make drilling variables to the optimum level and give a computational optimized well. Finally, primary and secondary optimizations were combined together to reduce drilling rate and cost as much as possible.
An optimal well, which can improve drilling time 30 % to 180 % in relation to the wells, drilled and save a considerable amount of drilling cost was designed for Khangiran field after applying optimization techniques.
The significance of this research is to reduce the time and cost for drilling the next wells in Khangiran field. In addition, the same techniques can be applied in other hydrocarbon fields to reduce costs and time of drilling operation.
Applied Newly Developed Technology to Overcome Deepwater Completion Difficulties
Authors: Mohamed Omar Y. , Waters Ray , Eid Said , Aly Taher , Hassaballa Sherif Aly 
Published: December 2007

Abstract
A major issue for the deepwater high-rate gas completions in the Simian/Sienna field off the coast of Egypt was the placement of an effective sand-control completion in the presence of highly reactive shales. Analysis showed the most productive completion method to be an openhole completion. However, this presented a challenge, as the shale encountered during the drilling phase was very reactive and could destabilize during completion equipment placement or during pumping operations such as gravel packing.
One of the most concerning obstacles of open hole gravel packing is exposed reactive shales that can destabilize. If the shale section of the wellbore swells or flakes off, they can prevent running of the gravel-pack assembly to bottom, plug screens and/or collapse into the wellbore to prevent complete gravel placement. Isolating the shale section behind casing will solve the problem; however, this process most often means having to reduce the screen size to be used, which may impede production.
A completion design using two newly developed technologies and other carefully selected proven techniques was applied to minimize the risks of shale instability. A new design of an alternate path screen system was chosen because of its ease of assembly, ability to transport gravel-pack slurry past annular blockages such as collapsed shales and its minimization of slurry exit velocity from the alternate path tubes while packing. Another new technology that was selected for application was the use of a non-ionic visco-elastic surfactant to transport the gravel-pack sand downhole. This fluid was chosen for its shale stability properties, excellent sand suspension properties and the high-return permeability characteristics of the fluid. Application of these technologies and observing other best practices mitigated the risks associated with gravel packing in an open hole in the presence of reactive shales.
Simulation Investigations for Enhanced Performance of Beam Pumping System for Deep, High-Volume Wells
Authors: Ghareeb Mohamed M. , Shedid Shedid A. , Ibrahim Mazher 
Published: December 2007

Abstract
Worldwide there are almost 920,000 producing oil wells, about 87 % of these wells are operated using different artificial lift methods and roughly distributed as: 71 % are producing using beam pumping system, 14 % using electrical submersible pumping (ESP), 8 % using gas lift and 7 % using all other forms of lifting systems.
This study was undertaken using advanced predictive methods, high strength rods, optimum pumping mode, and unit geometry to optimize the performance of beam pumping system for deep high volumes oil wells. Three geometries of different surface pumping units were analyzed and studied including, conventional, Reverse Mark and Mark II units. Each geometry of these three types has been subjected to different design features that affect torque and different linkages affecting its kinematics behavior. The highest strength sucker rod string, beam unit geometry, stroke length, pumping speed and subsurface pump size were varied and analyzed jointly to obtain optimum pumping parameters capable to produce maximum fluid at different well depths. This study considered and applied many variables including; well depths from 1,000 to 15,000 ft, three different rod grades, water cuts from 0.0 to 100 %, different pump sizes from 1.25 to 5.75 in, stroke lengths from 100 to 260-inch, and non-API sucker rod grades.
The results indicated that the lifted liquid volumes and pump seating depths for deep wells can be effectively increased using the beam pumping systems. The surface unit geometry has shown a crucial effect of increasing the produced quantity from deep wells. The study recommended using conventional pump unit for shallow depths up to 8,000 ft. The enhanced geometry pumping units of Mark II and reverse Mark have been proven the superior type for deep high volumes wells because it required the least torque to lift the same quantity from different well depths. The study also presented successful field applications for deep wells producing high volumes.