bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Subsurface Pump Size and Setting Depth on Performance of Sucker-Rod Artificial Lift—A Simulation Approach
Authors: Shedid Shedid A. 
Published: April 2009

Abstract
The need for better understanding of sucker rod pumping process is heavily required. Many problems are still under investigation such as determination of the fluid level from surface, selection of the optimum pump size and the required pump setting depth to maximize the pumping rate in a particular well. The main purposes of this study are to investigate effects of fluid level over pump, pump size, and pump setting depth on the sucker rod performance. These goals are achieved using the Artificial Sucker Rod Pump (ASRP) design simulator with actual field data.
The results show that applying good fluid level from the surface and increasing the plunger stroke consequently increase the resultant pumping flow rate. Furthermore, good fluid level yields high pump intake pressure and results in a good pump fillage, which increases the pump efficiency. In addition, the analysis of the effect of pump size on rod stress shows that the increase of pump size increases the rod stress and increases the pump flow rate. Therefore, the plunger size must be selected according to both the required flow rate and the allowable sucker rod stress. With respect to the effect of the pump setting depth on the performance of the sucker rod pump, the increase of the pump setting depth reduces the pump flow rate and increases the rod stress. Actual Egyptian field data is used for the purpose of achieving this simulation investigation of the above-mention effects.
Economics of LNG Projects
Authors: Al-Saadoon Faleh T. , Nsa Abel U 
Published: April 2009

Abstract
The economic viability of a liquefied natural gas (LNG) project is evaluated using industry-wide data. The range of expenditure figures (both capital and operating) obtained from the literature is synchronized into a unit energy basis across the value chain – liquefaction, shipping and re-gasification.
A Base Case is adopted based on a single train of 4.2 million metric ton per annum (MMTPA) capacity for a round-trip distance of 6200 miles (from Nigeria to the U.S. Gulf Coast), taking one (1) month round-trip voyage. It is assumed that the plant requires a 4-year construction period and it operates for 350 days a year in evaluating the economics of the project.
Two measures of profitability are used in assessing the economic viability of the LNG project, namely rate of return (ROR) and undiscounted pay-out-time (POT). A Base Case is performed using a Base Case Capital Expenditure (Base Case CAPEX), 15% discount rate and 3.00$/MMBtu raw gas price. In addition, sensitivity analyses are carried out on CAPEX (using -20%, -10%, Base Case CAPEX, +10%, and +20%), on discount rates (using 10%, 15%, 20% and 25%), on raw gas prices (using 1.00, 2.00, 3.00, 4.00, and 5.00$/MMBtu) and on overall operating expenditures (OPEX) ranging between 4.7% and 14.7% of CAPEX.
The pay-out-times for the various scenarios considered at discount rates of 10, 15, 20 and 25% are 7.82, 5.18, 3.68 and 2.76 years after startup/commissioning, respectively.
The break-even prices range between 3.00$/MMBtu (at Base Case CAPEX less 20%, 10% discount rate and 1.00$/MMBtu raw gas price) and 12.10$/MMBtu (at Base Case CAPEX plus 20%, 25% discount rate and 5.00$/MMBtu raw gas price). The corresponding mark-ups range between 2.00 and 7.15$/MMBtu, respectively.
The break-even and mark-up prices increase linearly with increasing raw gas prices yielding slopes of 1.17 and 0.17, respectively. These relationships hold true with all 100 cases considered in the sensitivity analysis.
A general survey of LNG liquefaction processes is also included.
Property Evaluation of EOR Technology by Means of Expansive Granular Crosslinked Polymer
Authors: Wang Wei , Lu XiangGuo 
Published: April 2009

Abstract
This paper discusses the adjustment of water injection in oil formation by adding the expansive granular crosslinked polymer (EGCP) into the injection carrier.
Some pilot tests have been conducted in some reservoirs of Jiangsu, Daqing, Dagang, Shengli and Zhongyuan Oilfield, where water flooding recovery is low due to the channeling in heterogeous oil formation. All pilot tests succeeded in plugging higher permeability water zone to favor the injected water squeezing into lower permeability zones and driving more oil into wells, and the ultimate oil recovery have been obviously increased.
In this paper, laboratory experiments have been done to not only provide experiment data basis for the field application, but also provide the mechanism basis of the EGCP profile modification through porous media. The EGCP system is composed of EGCP and carrier. The carrying fluid should be chosen according to input rate, expansion ratio, transport capacity, EGCP anti-shear ability, and flow resistance. Besides, an optimization analysis based on laboratory data has been made on the types and concentrations of EGCP and carrier, EGCP slug size and EGCP injection time, and profile modification evaluation. Furthermore, micromodel test has been done to study the mechanism of EGCP profile modification. The input rate and expansion ratio of EGCP become smaller, however, the anti-shearing ability becomes strengthener with increasing the salinity of carrie. The water input rate and expansive ratio of EGCP became bigger in polymer carrier, compared with those in formation water carrier, while the anti-shear ability of EGCP became stronger in polymer carrier, the anti-shearing ability further increase with the increasing of concentration of polymer solution. The experiments show that the pressures at the core entrance and middle point can increase synchronously when using polymer solution as carrier. This phenomenon testifies that the ability of EGCP suspension transportation is better in polymer solution, micromodel test further testifies that EGCP has the flow characteristics of "transportation, trapping, re-transportation and re-trapping" when it is flowing through porous media, which is beneficial for diverting the direction of injection liquid to enter the unswept area. The alternation of transportation and trap still can be indicated by pressure changes. The EGCP technique has been further optimized by enlarging EGCP slug size and moving up EGCP injection time to enhance oil recovery. All of these will be beneficial to choose the proper EGCP and carrier, plug large channels, get a good profile modification effect and enhance oil recovery.
Acid Tunneling Stimulation in Oklahoma Limestone Using Coiled Tubing
Authors: Strasburg J. , Clark J. 
Published: April 2009

Abstract
With the recent increases in price of a barrel of oil and the growing scarcity of easily exploited oil, efforts to improve productivity of older wells have intensified. Some options for accomplishing this include re-stimulating the well and/or adding laterals that extend past the original wellbore. In open-hole limestone formations, one innovative technique can achieve both of these goals simultaneously, creating pre-stimulated "tunnels" that bypass existing near-wellbore damage to make contact with new reservoir rock.
The new technology relies on limestone's acid solubility and a coiled tubing-conveyed bottomhole assembly comprised of components that tilt the tool toward the formation. A high-pressure nozzle then jets acid to extend new tunnels from the wellbore. The technique is applicable in all open-hole wells drilled in carbonate formations and can be used to remediate old wells or complete multiple drainage tunnels in new wells.
This acid tunneling technique and tool have been utilized around the world. They were first used in the United States to create three additional tunnels in an Oklahoma well that has been producing since 1924. This paper will describe the acid tunneling tool and design along with: an operational timeline, summary of lessons learned during the United States operation, comparison of pre and post-job production information for the treatment.
Effective Wellbore Parameters and the Productivity of a Multi-Fractured Horizontal Well
Authors: Cvetkovic Branimir 
Published: April 2009

Summary
Continuous improvements during well completion in addition to stimulation technology renew the need for multi-fractured horizontal well modeling. The present work investigates the productivity of a well with fractures by means of semi-analytical late-time approximations. These expressions are related to a vertical and a horizontal well with a single-fracture production. The flow in a fracture that is coupled to a horizontal well is of uniform flux (or of infinite conductivity flow) and the fractures can be positioned transversally or longitudinally. To successfully measure the production efficiency of a fractured-horizontal well, the effective wellbore radius and the equivalent single-fracture half-length were introduced. The effective wellbore radius was defined for a vertical well and could be extended for its horizontal counterpart. The equivalent fracture half-length was defined for a horizontal well with a single-transversal and a single-longitudinal fracture. The late-time approximations were developed for a fractured horizontal well positioned in the middle of an infinite oil reservoir. The developed expressions were employed for a multi-fractured horizontal well in order to define an effective wellbore radius and an equivalent fracture half-length (for both the transversal and the longitudinal fractures). A series of solutions corresponding to various conditions were given in a multiple-fractured-horizontal well model. It was possible to verify derived effective parameters of a fractured horizontal well by using a fast, robust and facile software program, a screening-tool product, that has been of considerable benefit to companies in the petroleum industry.
Changing the Operation of Oil and Gas Fields From "Harvest" to "Process" Mode
Authors: Cramer Ron , Rodger George Joel 
Published: April 2009

Abstract
In the O&G industry the nature of well and reservoir operations are slowly, but relentlessly changing. The traditional operations sequence of events is to drill, complete, and then flow wells to production at a "reasonable rate," and the process will yield what Mother Nature delivers.
This is what we refer to "harvest mode." The problem with this approach is that the production is invariably sub-optimal, resulting in lost revenue for the field operator and potentially damaging the reservoir.
Tools exist to look at the operation as an integrated process whereby the reservoir, well, and the entire surface facilities are modeled/monitored to optimize production from each well and the field/reservoir as a whole. This is what we refer to "process mode."
Traditionally operators endeavor to minimize reservoir damage and maximize production by performing infrequent, manual production tests, and occasional in-well pressure tests, to determine optimal well conditions. Ironically when instrumentation/automation is added to an oil or gas well it is almost always for safety or operational reasons. For example the use of rod pump controllers so that pumps are not damaged when they run dry, or to control the pump to minimize energy consumption when the pump is not filling completely. Automation, in the form of instrumentation and control systems, is rarely installed on a well to optimize the production of the well.
This paper will discuss underlying problems, experiences and plans that operators and service companies have in this area of production operations. The key to moving to aforementioned "process" mode is to properly monitor and or measure the production from the wells. Some operators developed simple pressure and pressure drop monitoring system to help detect when well tests must be re-run, as opposed to routine testing. Many other operators have used Individual Well Monitoring or Individual Well Testing. Finally, in one case an operator is looking at using well monitoring and updating the surface and reservoir models to continuously optimize the overall operation.
The Digital Asset: Connecting People, Technology, and Processes in a Collaborative Environment
Authors: Grable Jeff , Wylie Glenda 
Published: April 2009

Abstract
World energy demand is increasing. The next trillion barrels will be harder to access, harder to find and will be in ever smaller accumulations. New discoveries will undoubtedly be more difficult to produce and will have to be done with fewer and dwindling experienced resources.
The industry has begun to accept change due to their desired demand for improved efficiencies. These efficiencies include integrating the workforce (both service and operating groups), improving quality and efficiency of workflows, and improving the technologies that are feeding into the "Digital Asset™" service. Such technologies are better formation evaluation measurements, better geological models, and faster reservoir simulators, better able to integrate production data for comparison to the geological models. Connecting people and improving technology and workflows allow the right decisions to be made at the right time while spending the least amount of effort.
Today, necessity drives new and more dynamic integrated operations; and more efficient working relationships are evolving. This paper will discuss the challenge of doing more with less, exploiting more difficult reserves while lowering costs, increasing profits while reducing risk, and speeding up work processes while cutting non productive time.
The answers lie with in a series of steps towards cultural change: utilizing real-time collaborative environments allowing simple workflow methodologies to be applied and feeding improved measurements into improved models while continuous optimization occurs while simultaneously actual operations occur.
Data Driven Surveillance and Optimization
Authors: Cramer Ron , Goh K.-C. , Dolan Mike , Moncur Charlie 
Published: April 2009

Abstract
Traditionally individual well oil, gas and water production is measured periodically e.g. monthly, using shared well test facilities. Consequently, oil and gas production from a cluster of wells is difficult to manage, leading to late diagnosis of production problems and slow and conservative handling of production constraints. FieldWare Production Universe (FW PU) is a software application developed by Shell that provides continuous real time estimates of well-by-well oil, water and gas production. FieldWare PU estimates are based on data driven models constructed and updated from production well tests and real time production data.
This paper will discuss use of FieldWare PU for continuous optimization by predicting changes to overall and individual well production as a result of changes to individual well production chokes, lift-gas rates or other similar set-points to maximize an objective function subject to various well and overall production constraints.
Viability Study of Implementing Smart/Intelligent Completion in Commingled Wells in an Australian Offshore Oil Field
Authors: Pari M. Nadri , Kabir A. H. 
Published: April 2009

Abstract
Simulating automated action of smart well components represents a challenge in forecasting performance of such wells, which is fundamental in their design decisions. For example, wells equipped with Inflow Control Valves (ICV) where zones have to be switched on, off or partially closed based on their performance relative to the rest of the wells/completions in the field which share the same surface network and facilities constraints.
In this paper we present a study that has been carried out to justify installation of a surface controlled ICV in a group of wells in an off-shore Australian field with commingled production. The merit of surface controlled ICV versus uncontrolled commingled production has been compared. A numerical reservoir simulator has been used to model reservoir performance and production from individual zones. Also, well and production network has been simulated using a well and Production Network Flow Simulators. An interface "simulation manager" is used to facilitate information exchange between the two simulation programs and optimization of the process. Proper control of ICVs is simulated based on reservoir and well-bore simulation data which will result in maximum oil production of field network system resulting in higher recovery. Also, we have done typical economic analysis for smart well completion implementation. The results show that smart completion is viable for this field.
Realizing Value from Real Time Well Monitoring In Greenfield Assets
Authors: Feineman David R. 
Published: April 2009

Abstract
BP's proprietary Integrated Surveillance Information System (ISIS) was deployed globally starting in 2006. The system delivers well performance data to petroleum engineers in field and office sites in near real time. The paper presents two case studies on implementing remote well performance monitoring on two Greenfield assets in Africa and Asia where distance, national culture, and language differences must be addressed as part of a technology rollout. Based on the case studies, there is evidence that Greenfield assets can adopt new ways of working and technology that allows them to surpass the performance on similar Brownfield projects.
4D: From Mainstream to Main Street
Authors: Levin Stewart A. 
Published: April 2009

Abstract
As highlighted at recent SPE conferences and workshops, the use of 4D seismic technology has become mainstream. Currently, 4D monitoring programs are used in more than 140 fields (Lumley, 2008). Indeed, many major companies now require 4D feasibility studies for all new reservoir development plans. However, the high cost of 4D monitoring has generally limited its use to large fields that require heavy expenditures to produce. There has been relatively little "trickle down" in the use of 4D seismic among smaller producers, service companies, and/or consultants. Is this poised to change?
Challenges to 4D market expansion include technical feasibility as well as various economic drivers. Expected seismic response changes may be too small to reliably detect and interpret. And, relatively few entities have the luxury of maintaining a dedicated, integrated geoscience and engineering team with 4D expertise. However, most experts agree that economics serve as the greatest barrier to 4D expansion. In addition, the recent decline in oil and natural gas prices has provided further disincentive for 4D application by operators. On the bright side, I will show that studying the world's distribution of oil and gas fields leads one to the conclusion that if 4D costs were to drop by a factor of three, the number of fields for which 4D becomes economically feasible would rise by a factor of at least ten.
I predict that 4D costs could drop to these levels in three to five years because of the confluence of factors that include: technology continuing to reduce acquisition and permanent instrumentation costs, continuing growth of computing capacity, and integrated software packages for effective 4D interpretation. Also, regulations and tax incentives are adding greenhouse gas geological storage to the 4D monitoring market, and new inventions and processes are expected to play a role as well.
The possibility of increased expansion of 4D seismic technology from mainstream to Main Street is highly significant in the oilfield services industry because it would open annual revenue opportunities for smaller players that could be collectively measured in billions of dollars.
The E&P Balanced Scorecard: Becoming a Strategy Focused OPCO Driven by Performance
Authors: Kadam Sandeep , Fonseca Christopher 
Published: April 2009

Abstract
This Middle East Oil & Gas company explores, develops and produces hydrocarbons. It strongly believes that a strategy focused performance management approach would enhance its capabilities of producing hydrocarbon in the most economical way and maximizing ultimate recovery from reservoirs.
The company launched an e-Performance initiative to communicate and execute strategy and to create a "Line of Sight" both top down and bottom up and enhance horizontal alignment and integration.
We designed and developed the Performance Management System through Balanced Scorecards -A series of workshops were conducted for the functions / divisions by a group of consultants consisting of experts in Oil & Gas and Performance Management-Strategic objectives, measures and targets were captured and the score cards were programmed in Excel with traffic signals
Initially the key performance indicators were captured in an Excel workbook. The next step was to automate the process of data collection and aggregation before presenting it for Performance Management. Several applications were reviewed for the purpose. The choice takes into account that the proposed IT architecture and application exploits to the maximum extent functionalities of the existing ERP system and other applications.
Key Performance Measures were defined for the Production Operations, Gas Division, HSE function, New Development, the support services of HR, Finance, IT, Medical and the corporate functions of Supply Chain, Planning, Legal among other departments.
The New Development comprised Engineering and major projects, exploration, development, planning and support and automation/smart field. New development was the most significant concern to the company since it would increase their daily crude oil production by 0.4 million bbls by 2012.
All employees were made aware of the balanced scorecard, its objectives and the process to be followed through extensive training and awareness sessions.
The Balanced Scorecard system needs to be integrated to the operational IT systems, databases and/or datawarehouses. It is necessary to refine the KPIs due to changes in influencing factors.
The Promise and Challenges of Digital Oilfield Solutions—Lessons Learned From Global Implementations and Future Directions
Authors: Sankaran Sathish , Lugo Jose , Awasthi Ankur , Mijares Gerardo 
Published: April 2009

Abstract
Digital Oil Field (DOF) in the oil and gas industry has gained momentum in the last few years and has transformed from being a vision to projects that have measurable value. The promise of DOF has motivated many oil and gas operators and service companies to now establish corporate initiatives and associated business programs to develop and deploy DOF solutions. Many major capital projects are already evaluating the feasibility of DOF in early stages of the project decision process as part of the operational philosophy.
However, the implementation of these projects over the last few years has unraveled a multitude of practical challenges and hurdles to achieve the DOF goals, including selecting the candidate of highest value opportunities in the business unit's portfolio, justifying a business case, establishing new management processes to address operational transformation, defining people roles and responsibilities in DOF work processes, forming a team of skilled personnel for development and support of installed solutions, recognizing fit-for-purpose models, identifying appropriate technologies for the rapid deployment of integrated workflows, lack of open architecture and standards, project management approach, and change management, among others.
This paper describes the challenges faced in DOF implementations by Halliburton and the current industry status. The case studies presented highlight these issues and practical lessons learned about addressing these issues using novel solutions and delivering value through adopting best practices. The paper also provides an insight into future trends and areas of development, addressing areas of challenges that still must be resolved.