bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Well Testing Operations in High-Pressure/High-Temperature Environment: Case Histories
Authors: Boscan Jorge , Almanza Edgar , Wendler Curtis 
Published: December 2007

Abstract
In the oilfield, high pressure/high temperature wells (HP/HT) are those with more than 10,000 psi bottomhole pressure and bottomhole temperatures in excess of 300° F. As such, the severe reservoir environment in these wells requires special testing equipment that can sustain the high pressures and temperatures. Special testing processes and equipment have been designed to reduce the risks in achieving successful evaluations, and HP/HT wells can be successfully tested under both rig-supported and rigless operations and in both cased- and openhole conditions. This paper will compare some of the testing experiences in HP/HT wells tested several years ago, and some that are more recent and have used new technologies to increase the success in obtaining the information needed for the evaluations.
With the new technology, it has been possible to transmit the data collected during the evaluation to offsite locations using internet capabilities, collect more accurate data using memory gauge systems capable of working at high temperatures, gather downhole real time data using various collection tools, improve well productivity by applying propellant technologies, and improve perforating performance by using state-of-the-art charges.
The paper will describe the downhole tool system used to perform the well testing evaluation under severe well conditions. Also discussed will be how it was capable of acquiring well data in real time, and then, disseminating it over the Internet to allow collaboration with a larger number of individuals. This allowed immediate decisions concerning operational or program changes to be made and implemented at the wellsite.
The system has been successfully deployed on a number of well tests in Australia and Venezuela, and the paper will present some of these case histories as illustrations of the well testing capabilities now possible in varying conditions
Sandstone Acidizing Treatment of a Horizontal Openhole Completion Using Coiled Tubing from a Deepwater Floating Production Platform
Authors: Hardin F. Lee , Barry Mike D. , Shuchart Chris E. , Gdanski Rick D. , Ritter D. Wes , Huynh David V. 
Published: December 2007

Abstract
A sandstone acidizing treatment was performed on a 1550-ft horizontal open-hole gravel packed completion to restore productivity following impairment by fines migration. Extensive pre-job laboratory testing was conducted to identify the optimum treatment recipe. The treatment was placed utilizing coiled tubing on a floating production platform and pumped from a marine stimulation vessel. Pre- and post-job production logs were run to verify treatment effectiveness. This paper focuses on the problem identification, treatment design, and measurement of results.
Downhole Permanent Monitoring Tackles Problematic Electrical Submersible Pumping Wells
Authors: Macary S. , Mohamed I. , Rashad R. , El-Noby M. , A/Latif M. , Awni I. , A/Khalek M. 
Published: December 2007

ABSTRACT
Permanent monitoring of downhole equipment and production in artificial lift wells is an excellent method of diagnosing conditions and determining the appropriate approach to avoid loss of production or of the well.
Belayim Petroleum Company in Egypt (Petrobel) has used permanent monitoring sensors since 1994. The systematic data are used by the reservoir and production engineering staff to tackle problems such as high failure rate, sand fill-up, scale, ESP wear, and electric failures.
Petrobel currently has twenty downhole gauges, and 8 other systems are waiting associated accessories before installation. Each permanent gauge sends nine measurements per minute to the surface in real time yielding an incredible volume of information.
Downhole gauges supply accurate information about the reservoir, downhole, and the pumping system. This knowledge, in turn, is used to increase the run life of the artificial lift system through optimization of the reservoir pressure and artificial lift system performance.
This paper demonstrates the long-term benefits of using subsurface permanent gauges to complement artificial lift equipment and provide real-time data to optimize well and/or field production. Case studies illustrate both offshore and onshore problems. Examples are given of wells that have been converted into successful artificial lift completions through proper interpretation of the gauge measurements and use of the information to optimize production. This paper brings data interpretation to a new level of prediction, which enhances economics and minimizes risk in production operations, especially offshore.
A Modern Approach to the Optimum Design of Sucker-Rod Pumping System
Authors: Firu L. S. , Chelu T. , Militaru-Petre C. 
Published: December 2007

Abstract
This paper presents an improve optimization criterion that permit to select the optimum pumping mode from a large number of combinations of pumping rod parameters. The function that modeling the optimization criterion represent the sum of non-dimensional pumping rod parameters. The optimization criterion developed, includes eight operational parameters that characterizes the sucker-rod pumping system: (1) the maximum polished-rod load, (2) the maximum polished-rod stress, (3) the safety coefficient at variable loads, (4) the asymmetry coefficient, (5) the stroke efficiency, (6) the volumetric efficiency, (7) the buckling length of the sucker-rod string and (8) the performance index. Each of these parameters can influence the efficiency of the pumping system.
In order to select the optimum pumping mode, calculations must be made covering a wide range of variables. If four rod sizes are selecting with the available polished rod stroke lengths, pumping speeds (from 3 to maximum SPM of the pumping unit) and six plunger diameters, there are approximate 2200 possible pumping modes that may be considered. The optimization criterion proposed permit to select (using the computer program) only one pumping mode considered the best that correspond with maximum efficiency. The design technique used, allows prediction of surface dynamometer card using the exact kinematics parameters of pumping units, static loads, fluid friction along the string and dynamic rod loads, and the downhole cards based on solutions of the wave equation. Also, the main pumping rod parameters and the length of rods in compression are calculated. The result of this work is a complex computer program based on improve optimization criterion and pumping system design calculations. The application of this criterion for many suckers pumping wells, increases the efficiency of pumping system.
Safety Critical Systems Principles Applied to Drilling Engineering and Well Services Software
Authors: Sawaryn S. J. , Sanstrom B. , Williamson H. , Kirkman M. , McColpin G. 
Published: December 2007

Abstract
Drilling and Well Services software such as casing design, directional collision avoidance scans and well control applications were introduced as Safety Critical Systems in the paper SPE 73893. A serious, undetected failure in the development or use of one of these products could result in loss of life or catastrophic environmental damage. It was concluded that safety-critical software should only be used within the strict confines of a controlled management system, where software integrity, change, data, process and people competency are all tightly managed. Audits were used to identify best practice and areas for improvement.
The paper describes aspects of the controlled management environment developed over the last 18 months in response to the audit's recommendations. The first step was to introduce a series of principles covering software development, implementation, fault tracking and use. These principles are now incorporated as standards, supporting the BP Wells Policy. Both safety and business critical components are now formally incorporated in the vendor's, Landmark Graphics development process. Major reviews involving other operators have been conducted on the casing design and well control applications. A complete listing of the principles is provided in the paper. Their application is illustrated using examples from the casing design, well control, pore pressure, fracture gradient and directional applications. Simple procedures used to track both progress and adherence to the principles are also presented.
Colorado E&P Storage Tank Emission Factor Development
Authors: Smith Ty J. , Wonstolen Ken 
Published: December 2007

Abstract
A simple, cost effective methodology was sought to calculate storage tank emissions for exploration and production (E&P) operators in Colorado. This effort was prompted by a proposed regulatory change that would eliminate the exemption of crude oil and condensate storage tanks from emission reporting/permitting requirements. Due to the potential economic impact to the producers of over 14,000 existing wells across the state, the Colorado Oil and Gas Association (COGA) proposed a study to characterize the emissions from these E&P storage tanks to the Colorado Air Pollution Control Division (APCD).
COGA, with the involvement of the APCD, contracted Lesair Environmental to conduct the emission study. Using existing data from the Oil and Gas Conservation Commission, a sampling strategy based on applicable producing areas was developed and implemented. Sample analysis results were then used to calculate theoretical tank flash emissions using two different process simulation software packages, E&P Tank v2.0 and PROSIM 98.3. The resulting emissions from each sample were compared using several parameters.
Upon completion, the study results were presented to the APCD. In a cooperative effort, statewide and specific producing area emission factors were developed for both volatile organic compounds and individual hazardous air pollutants. Use of these factors allows an E&P operator to need only an annual tank throughput to estimate the emissions from the storage tank. In addition to the benefits derived from this simple, cost effective emission estimation methodology, COGA was able to help the APCD understand some of the unique issues associated with regulating air quality emissions from E&P operations.
Reducing Well Delivery Unit Technical Cost Using Expandable Sand Screens ESS With Medium Radius Technology On Sidetrack Wells
Authors: Oluwatosin A. O. , Adegborioye A. M. , Anya S. O. 
Published: December 2007

Abstract
The drive for continuous reduction in the Unit Technical Cost of oil production led to the kick-off of a Medium to Intermediate radius Horizontal Sidetrack Campaign in 1999. This campaign planned to deliver 18 wells and increase production by sidetracking existing wells and landing them at horizontal with 12 - 45°/100ft dogleg severity. The plan was to increase production by 33MBOPD with an average cost of $1.5m per well over the 18 well campaign, resulting into a UTC of 3.2 $/bbls; See Table 1& Appendix D.
The availability of technology for medium radius trajectory drilling in combination with the successful deployment of Expandable Sand Screen (ESS) in Shell Petroleum Development Company Nigeria (SPDC) provided a trial opportunity for the campaign to reduce cost and increase production in it's 3rd well. This was to provide the option of ESS implementation in the subsequent horizontal sidetrack campaign wells.
The ESS was deployed at doglegs up to 18°/100ft proving the efficacy of the integration of ESS technology with medium radius applications. The introduction of the Expandable Sand Screen (ESS) technology in the 3rd well of the campaign led to an increase in production of 2,000 BOPD with a corresponding reduction in UTC of 63%. This integration of ESS technology with medium radius well technology has increased the toolbox options for brown field development in Nigeria and the world at large.
This paper focuses on the challenges involved in the planning and execution of the wells using medium radius and ESS technology. It emphasizes the well design issues and the ESS deployment design challenges. Finally, it reviews the milestones achieved and the high impact on overall well economics.
Stimulation of High-Temperature Sandstone Wells in Steam Drive and SAGD Areas
Authors: Henderson Greg J. , Nokonechny Stacey , Meyer Russ 
Published: December 2007

Abstract
Steam drive and SAGD (Steam Assisted Gravity Drainage) are common methods of producing heavy oil in many areas of the world. Feedstock water is taken from a local water source, converted to steam and pumped down an injector well. The steam heats the fluids in the formation reducing the native bitumen viscosity allowing it to flow to a nearby producing well. This process has the potential to produce several damage scenarios including carbonate and/or silicate scales, asphaltene deposition or formation fines migration. A procedure has been developed to remove formation damage and provide matrix stimulation in the shallow, extremely high BHT (200°C), sandstone wells in producing Steam Drive and SAGD wells.
The producer's wells covered in this paper are located in the heavy oil region of Bolney, which is northeast of Lloydminster, Alberta, Canada. In many cases, the horizontal section of the producing wells are completed using slotted liners consisting of alternating blank and slotted sections. The slotted liner helps prevent sand production and maintain wellbore integrity while still allowing fluid inflow to occur. In addition to the original liners, most of the Bolney producers had additional screens put inside the liners that provided a smaller slot size. This was done to help with fine sand production problems the field experienced after initial completion. This completion configuration presents challenges in stimulating the ‘behind’ pipe formation which also includes the space between the slotted liner and open hole and the near wellbore region.
The acid treatment involves various pre-flush fluids and a unique retarded hydrofluoric acid system that results in the slow release of hydrofluoric acid in the formation to yield deep penetration into high temperature sandstone reservoirs. Not only is the reaction with fines and clays retarded, the retardation chemistry stabilize reaction products in spent acid to help control precipitation damage.
Over a time period of five years, information from various analyses was obtained which confirmed some of the damage mechanisms that can be present in the producing wells. Two particular wells, which are presented in detail, have been treated on three occasions over these five years and on each treatment, a different volume of stimulation fluid and a separate application technique has been utilized. Each treatment produced a markedly different production profile. The production increase can be correlated to the treatment type and volume of fluid used. Presented in this paper is the evolution of the process where multiple wells where stimulated utilizing various treatment types and volumes and the resulting production analyzed to optimize the process.
Multiple Precision Hydraulic Fractures of Low-Permeability Horizontal Openhole Sandstone Wells
Authors: Hoch Ottmar , Stromquist Marty , Love Gordon , Argan John 
Published: December 2007

Abstract
Many horizontal wells with openhole completions have been drilled in low-permeability sandstone formations. The Cardium formation in west-central Alberta, Canada is one such case. Many of these wells perform below predicted rates with uneconomical gas production. Until recently, no method existed to effectively fracture stimulate this type of wellbore to optimize production.
Possible reasons for low production rates in these wells include vertical heterogeneity of the sandstone, low horizontal permeability, and much lower vertical permeability. The heterogeneities in the sandstone can act as barriers to vertical flow. Near wellbore damage is another possible reason for low production. One way to neutralize the effect of these barriers or damage is to hydraulically fracture the formation, effectively connecting the full porous height of the formation to the wellbore through a propped vertical fracture. Nevertheless, if only one hydraulic fracture is placed, the horizontal wellbore may not produce more than a vertical well. A new hydrajet-fracturing technique, however, now exists whereby many propped hydraulic fractures can be placed individually at strategically selected locations along an openhole wellbore. The resulting horizontal wellbore with multiple propped fractures can potentially produce gas at rates higher than those of a vertical well.
This paper briefly describes the hydrajet-fracturing process and documents two case histories from the Cardium formation in which this system was applied. Both wells were hydraulically proppant fractured at multiple locations precisely placed along their openhole horizontal wellbores.
A Step Change in Collaborative Decision Making - Onshore Drilling Center as the New Work Space
Authors: Herbert Mike , Pedersen Jarle , Pedersen Terje 
Published: December 2007

Abstract
For years, offshore shuttling to accommodate insufficient bed-space has invoked a safety risk for offshore workers. A North Sea operator has overcome this by implementing tools to dramatically change the normal work flow in decision making.
Since 1999, the mudlogging crew on the Ekofisk Platform in the North Sea has been performing well monitoring from the operator's onshore office in Tananger, Norway. The deployment of a fiber optic network in this area of the North Sea has provided the means for a reliable workflow with the benfit of reduced travel to the rig and improved integration between onshore and offshore teams.
Building on these experiences, a concept was developed to take a "Step Change In Collaborative Decision Making" by building a completely new Onshore Drilling Centre (ODC) and real time data monitoring system. Project planning started in February 2002 and the center was opened and functional by 6 November 2002.
A visualization, telecommunication and data-sharing network and well monitoring system has been developed and installed to assist the offshore operations on a twenty four hours, seven days a week basis
In addition to reducing offshore travel, the objective of the ODC is to reduce the number of iterations in well trajectory planning, reduce drilling cost, improve geosteering decisions and improve integration between drilling and geology, hence reducing unwanted safety incidents while drilling.
This paper describes the technology, people and processes employed to build the ODC. The new work flow in well planning and execution of drilling complex ERD and horizontal wells from the ODC is described. Preliminary results from these new collaborative work processes will be outlined.
Underbalanced Drilling with Casing Evolution in the South Texas Vicksburg
Authors: Gordon Doug , Billa Rich , Weissman Mike , Hou Fu 
Published: December 2007

Abstract
Drilling with production casing while underbalanced is improving the drilling performance dramatically in South Texas fields. This approach allows drilling of depleted and high pressure sands intermingled within one hole section, resulting in significantly less expensive well plans. Drilling cost reductions of 30% have been realized. Smaller reserve targets are viable, a key advantage in the mature South Texas Vicksburg play.
Comparison of Minimum Miscibility Pressures Determined from Gas-Oil Interfacial Tension Measurements with Equation of State Calculations
Authors: Ayirala S. C. , Rao D. N. , Casteel Jerry 
Published: December 2007

AbstractMiscible gas injection has been widely used as the most popular enhanced oil recovery process for light oil reservoirs. For technical and economic success of miscible gas injection projects, an accurate laboratory measurement of minimum miscibility pressure at reservoir temperature is essential. In addition to the existing laboratory techniques of measuring MMP namely slim-tube and rising bubble, recently a new technique of measurement called vanishing interfacial tension (VIT) has been developed. This new technique enables rapid and cost-effective determination of MMP. Hence, the objective of this study is to compare the minimum miscibility pressures determined from gas-oil interfacial tension measurements with those obtained from phase behavior calculations based on equations of state (EOS). For this purpose, two commercial crude oils namely Rainbow Keg River (RKR) and Terra Nova have been used, since the PVT data necessary for EOS calculations and the experimental values of MMP were available for these two reservoir cases. Peng-Robinson (PR) equation of state within a commercial software package has been used. The effects of tuning and non-tuning the equation of state on MMP calculations have been examined.For the two reservoir cases considered in our study, tuned PR-EOS yielded significant differences between MMPs from EOS calculations and VIT measurements, while untuned PREOS yielded reasonable match with experiments. In the case of RKR crude oil, the untuned EOS predictions were consistently higher by about 3.0-5.0 MPa than the experimental MMP from the VIT technique. For Terra Nova crude oil, in three out of five cases studied, the visible MMPs from the VIT experiments reasonably matched with untuned EOS calculations. Therefore, these comparisons of VIT results with EOS predictions clearly demonstrate that this new technique of vanishing interfacial tension is quite promising and reliable.