bluuebunny/crossref_metadata_2025_split huggingface dataset:
Practical Considerations for Pressure/Rate Deconvolution of Well-Test Data
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90680, "Practical Considerations for Pressure/Rate Deconvolution of Well-Test Data," by Michael M. Levitan, SPE, BP plc; Gary E. Crawford, SPE, WTS; and Andrew Hardwick, SPE, BP plc, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Pressure/rate deconvolution provides equivalent representation of variable-rate well-test data in the form of characteristic constant-rate-drawdown-system response. Deconvolution enables additional insights into pressure-transient behavior and extracting more information from well-test data than is possible with conventional-analysis methods. In some cases, it is possible to interpret the same test data in terms of a larger radius of investigation.

Introduction
Evaluation and assessment of pressure-transient behavior in well-test data usually begin with examining test data by use of different analysis graphs [e.g., Bourdet derivative graph, superposition (semilog) graph, and Cartesian graph]. Each graph provides a different view of the pressure-transient behavior that is hidden in the test data by the production-rate variation during a test. Integrating these views into one consistent picture enables recognizing, understanding, and explaining the main features of the transient-pressure behavior. A new method of analyzing test data in the form of constant-rate-drawdown-system response uses a pressure-/rate-deconvolution algorithm.
Deconvolved drawdown-system response is another way of presenting well-test data. Pressure/rate deconvolution removes the effects of rate variation from the pressure data measured during a well-test sequence. It reveals the underlying characteristic system behavior that is controlled by reservoir and well properties and is not masked by the specific rate history during the test. In contrast to a Bourdet derivative graph or to a superposition graph, which display the pressure behavior for a specific flow period of a test sequence, deconvolved drawdown response is a representation of transient-pressure behavior for a group of flow periods included in the deconvolution. As a result, the deconvolved system response is defined over a longer time interval and reveals features of transient behavior that would not be observed with conventional analysis.
Techbits: Progress in Horizontal Technology Yields Incremental Bonuses
Authors: JPT staff _ 
Published: February 2015

Nearly 110 participants in an SPE Applied Technology Workshop (ATW) on Horizontal Wells heard Pemex Subdirector of Technical Coordination Heber Cinco Lay and Canadian Triton Intl. President and ATW Chairperson Jack Nelson explain synergistic developments that have contributed to elevating horizontal drilling to a qualified, viable alternative to vertical wells. Held in Tabasco, Mexico, the 2-day ATW stressed the importance of lateral-drilling technology to Pemex operations and invited knowledge exchange.
Referencing the industry's steep learning curve with multilateral drilling, Nelson traced the progression of lateral-well technology from the first recorded true horizontal well drilled near Texon, Texas, in 1929 to the Austin chalk and Bakken shale successes during the 1980s to horizontal displacements running to more than 23,000 ft in the Dan field. The technical program, consisting of eight sessions, featured 25 speakers from major operators and service companies presenting on the following topics:Why and When To Plan To Drill Horizontal—Included a case history on the Agua Fria field, increasing productivity using lateral-well technology, application-risk-evaluation barriers and limitations, and an update on specific horizontal-well technology.Geomechanics and Advanced Wellbore Modeling—Included horizontal-wellbore stability issues; effect of anisotropy on productivity ratio for high-permeability, naturally fractured reservoirs; and workflow based on an integrated Earth model.Horizontal Drilling Techniques—Included wellbore quality and effect on drilling and completion, underbalanced lateral drilling, and well construction.Horizontal Completion Techniques—Included the candidate selection process for horizontal, openhole completions; openhole horizontal-well sand-control completion options; and practical installation of an expandable sand-control screen.Well Intervention Issues and Remedial Operations—Included the importance of geomechanical parameters in horizontal drilling, wellbore-debris-management systems, and use of swell packers for zonal isolation in long deviated horizontal and multilateral open holes.Evaluation of Horizontal-Well Performance—Included a case history of Chevron's Captain field (an offshore heavy-oil horizontal-well development project) and stimulation of horizontal wells in low-permeability, deepwater, carbonate reservoirs.Workflow Process: Keys to Success—Included discussion of Pemex's "front-end loading" modeling and design methodology, the impact of digital technologies on planning and drilling horizontal wells, and motivations for drilling horizontal and multilateral wells in the Faja Petrolifera del Orinoco in Venezuela.New Technologies and New Challenges—Included techno logical advances in horizontal gravel-pack systems, use of horizontals for heavy oil in deep water, and a case history of an expandable screen applied to a horizontal gas well in Mexico.
Modeling Laser-Spallation Rock Drilling
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 95746, "Modeling of Laser Spallation Drilling of Rocks for Gas- and Oilwell Drilling," by Z. Xu, SPE, Y. Yamashita, and C.B. Reed, Argonne Natl. Laboratory, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.
High-power lasers can weaken, spall, melt, and vaporize Earth materials, with thermal spallation being the most energy-efficient rock-removal mechanism. The most interesting focus of recent laser rock-drilling research is on developing a laser rock-spallation technique to drill large and deep holes in rocks. Laser spallation has a rock-removal rate higher than conventional rotary drilling and flame-jet spallation. Research also is focused on the use of laser rock spallation to make perforation channels with improved permeability of the perforated rocks.

Introduction
Laser rock spallation is a rock-removal process that uses laser-induced thermal stress to fracture the rock into small fragments before it melts. High-intensity-laser energy, focused on a rock that has very low thermal conductivity, causes the local rock temperature to increase instantaneously. This results in a local thermal stress that spalls the rock. Previous test data show that laser rock spallation is the most energy efficient among all laser rock-removal mechanisms. Recent research and development concentrating on use of advanced high-power lasers to drill and complete oil and gas wells has focused on two fronts. The first was to develop a multibeam laser rock-spallation technique to drill large and deep holes in rocks with a rock-removal rate higher than that of conventional rotary drilling and flame-jet spallation. In this approach, each laser beam spalls a hole as big as the beam spot and half the beam diameter deep. Multiple beams are overlapped to remove a layer of rock. Layer by layer, a large and deep hole is drilled. The second focus was to develop a laser rock-perforation technique for oil- and gas-well completion applications. Perforating oil and gas wells requires creating a hole through a composite structure of steel casing, cement, and formation rock. Current explosive-charge perforation methods, while capable of creating the holes, significantly reduce the rock permeability. Laboratory tests demonstrate that laser beams not only cut rocks efficiently, but also increase the permeability of spalling-drilled rock significantly. An innovative laser perforating system will allow the oil and gas industry to improve injection and production rates.
Overview: Offshore Facilities: Construction and Design (February 2006)
Authors: Valenchon Claude 
Published: February 2015

The current high prices of oil and gas and the opinion shared by many oil operators that they will remain high in the future will lead to development of oil reserves having a higher technological cost than development activities in the past. For the offshore industry, this expectation of higher prices will translate into new opportunities and result in major growth in deepwater-development activities.
Even if most of the large deepwater fields have already been discovered, at least in the traditional deep offshore zones of the U.S. Gulf of Mexico, Brazil, Nigeria, and Angola, many smaller discoveries with reserves ranging from 100 to 300 million bbl have been made and probably will continue to be made in deep and ultradeep water.
Development of these fields presents several technical and economic challenges.Smaller reservoirs are uneconomical under conventional development schemes.Uncertainty exists regarding the fluid properties and the extent of reserves because fewer appraisal wells are affordable.Number of production wells per field is limited.Tieback distances to existing facilities or to the coast are long.Obtaining fluid properties is a challenge, and there is a lack of homogeneity with neighboring accumulations.
Development of these small discoveries will be made possible either as satellites to an existing facility, even with very long tiebacks, or as standalone developments by grouping small adjacent fields that sometimes are far apart and have different fluid properties. These development projects will require technologically added value such as innovative field architectures, cost-effective flowline and riser solutions, multiphase pumping, subsea separation (gas/liquid or three-phase), and efficient monitoring.
Concerning the development cost, the portion allocated to drilling, flowlines, risers, and subsea hardware will be higher than in current deepwater developments. In the process of transferring equipment from surface to seabed, operators will need assurance of at least comparable availability of the facility as that currently achieved through a combination of equipment reliability, adequate redundancy, and efficiency of maintenance.
Offshore Facilities: Construction and Design additional reading available at the OTC Library: www.otcnet.org
OTC 17255 "Regulatory Philosophy Concerning U.S. Coast Guard's Concept-Review Process," by L. Rodriguez, U.S. Coast Guard, et al.
OTC 17180 "Evaluation of Wave and Current Loads on Offloading FPSOs" by X.-B. Chen, Bureau Veritas, et al.
OTC 17740 "Implications of Hurricane Ivan on Deepwater Gulf of Mexico Metocean Design Criteria," by C. Cooper, ChevronTexaco Energy Technology Co., et al.
Petroleum Industry 2020: People First: People KPI
Authors: Al-Khalifa Abdul-Jaleel 
Published: February 2015

Our industry leverages talent and technology to extract the maximum benefit of hydrocarbon resources. The ultimate objective, of course, is to enhance the socio-economic development and well-being of human kind. Our industry business model towards achieving this noble objective has over the years resulted in corporations that follow a market economy. Is this the best and most efficient business model? Are we maximizing the benefit of hydrocarbon resources—that is, are we finding and recovering the highest volume of hydrocarbons in the most cost-effective way? The answer, unfortunately, is no. For example, the current ultimate oil recovery averages 35%. This is very low compared to the maximum physically allowable recovery of 70 to 80%. The current finding success ratio is only 20 to 30%, which can be improved to 50%.
Can we enhance our business model to achieve these objectives? The answer, fortunately, is yes. So, why do not we do it? I believe that both our current financial model and corporate cultures require a fresh look and major reforms. Last month, I emphasized the role of leaders in changing corporate cultures, such as setting fair policies and living the values of fairness and excellence in their day-to-day actions. Corporate leaders can walk this talk and start assessing and reporting a people key performance indicator (KPI) that reflects their sincere desire to support their people and to boost the performance of our industry.
I will explain the proposed people KPI, and then will continue last month's analysis of our current financial model.

People KPI
I strongly believe that a frequent companywide assessment of workforce engagement is essential. Results can be reported as a people KPI and shared with all stakeholders. This KPI will complement other reported indicators, such as quarterly earnings, cost per barrel, and reserve replacement ratio. This KPI is essential for two reasons: it promotes the value of people, which is the right thing to do; and it will improve the performance and extend the life of our industry.
A people KPI is extremely important for all stakeholders:Corporate boards can monitor the performance of their executives in relation to people issues. Similarly, executives can assess the performance of middle management and institute immediate changes when needed,Employees will communicate their concerns, remain engaged, and continue to be innovative.Investors and market analysts can utilize the people KPI to assess a company's long-term viability. This will complement the quarterly earnings data that reflect short-term performance.
Survey Focus and Results. Healthy organizations tap the hearts and minds of their people, and help them draw on their utmost potential in a happy and engaging environment. These organizations enjoy the brightest innovations and the most cost-effective performance.
Western Siberia Sees Improvement in Drilling Efficiency
Authors: JPT staff _ 
Published: February 2015

Achieving significant improvements in drilling efficiency is most often the result of an integrated approach. First, the appropriate combination of hardware and software tools must be selected for the particular task to be accomplished. The second requirement is an experienced, dedicated directional-drilling team capable of seamless timely communication with the operator. This combination recently delivered excellent results on a large-scale field-development program in western Siberia.
Sibneft-Khantos operates the South Priobskoye field in the Khanty-Mansiysk autonomous region of western Siberia (Fig. 1). The Priobskoye fields straddle the Ob River and are among the most productive oil fields in a region known for prolific oil fields. Starting in 2005, the company launched an ambitious development program designed to place 200 wells on production each year while optimizing drilling processes and while saving time and money by streamlining procurement and logistics programs. A combination of Russian and foreign service/supply companies was to be used, so it was essential to establish clear procedures and work able metrics by which progress could be monitored and evaluated. Specific goals included using the best-substantiated drilling technologies to reduce drilling time, simplify well design, reduce environmental impact, and improve well quality. Historically, all drilling had been performed employing local service companies using rigs equipped with nonrotating aluminum drillpipe and locally manufactured mud turbines.
The operator identified five focus areas for improvement:Upgrading of drilling rigs and drillstring components.Drill-bit procurement and supply-chain management.Drilling efficiency and wellbore quality.Improvement in drilling-fluid properties.Improvement of cementing efficiency and quality.
Wells at South Priobskoye are pad drilled, generally following an S-shaped profile with average lateral displacement of 3,182 ft from the surface location. Typically, the casing program consists of 12 3/4-in. surface pipe, a 9 5/8-in. intermediate section, and a 7-in. production interval. In addition to improving drilling efficiency, Sibneft was concerned with ensuring that all wells were landed precisely in the target formation and that borehole angle-build rates never exceeded design criteria. In addition, because of the number of wells emanating from each drilling pad, there was a risk of borehole collisions. Accordingly, procedures to prevent this were an essential part of the plan and the subsequent practice. Finally, the company was determined to minimize unnecessary borehole extensions or sidetracks.
Cement-Bond-Log Interpretation Reliability
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101420, "Reliability of Cement-Bond-Log Interpretations Compared to Physical Communication Tests Between Formations," by Douglas Boyd, SPE, Salah Al-Kubti, SPE, Osama Hamdy Khedr, SPE, Naeem Khan, and Kholoud Al-Nayadi, SPE, Zadco; Didier Degouy, Adma-Opco; and Antoine Elkadi and Zaid Al Kindi, SPE, Schlumberger, prepared for the 2006 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 5-8 November.
Two kinds of cement-bond-log (CBL) tools are run as part of a standard cement-evaluation program. The effectiveness of these tools and their evaluations often are challenged, and they are not regarded as a replacement for reservoir interzonal-communication tests performed between producing reservoirs. The value of continuing to run these tools was questioned by management. In response, the reliability of these tools and their ability to determine the existence of poor behind-casing cement quality were examined.

Introduction
Historically, three methods are used to check for isolation between reservoir units. Pressure tests are restricted to localized areas of the casing such as the casing/liner shoe and squeeze perforations. Communication tests, regarded as the most definitive method of testing behind-casing isolation, jeopardize casing integrity and are costly. Cement-evaluation logs are time-efficient, cover the majority of the casing, and are inexpensive compared to communication tests. Interpretations of these logs sometimes do not predict behind-casing communication, creating a perception of unreliability. Determining the confidence that can be placed in cement-log interpretations is an objective of this task force.
Behind-casing communication of hydrocarbons via the cemented annular space requires expensive remedial cement squeezes to cure the problem. Because of the importance and criticality for reservoir management of the zonal isolation between oil-bearing formations, Zadco's policy is to confirm isolation by physical communication tests regardless of the quality of cement interpreted from CBLs. Only cement barriers between formations where production is planned are tested. Intervals between reservoirs not planned for production are not tested.
Because the majority of cement-squeeze decisions are based on the results of physical-communication tests, the value of continuing to run CBLs was questioned. A task force comprising representatives from drilling, well integrity, petroleum engineering, petrophysics, and the primary service company was formed to review Zadco's communication-test policy and determine the reliability of CBLs to determine behind-casing cement quality and from this infer the presence or lack of isolation between formations.
Techbits: Workshop Examines Resources, Reserves, and Development
Authors: JPT staff _ 
Published: February 2015

Techbits
More than 65 technical specialists, representing 32 Organizations in nine countries, attended the SPE Applied Technology Workshop (ATW) "Resources to Reserves for Asset Development," held 18–21 November in Penang, Malaysia. This was the fourth in a series of work-shops being organized under the auspices of SPE's Oil and Gas Reserves and Reserves Education committees.
The goal of the ATW was to highlight the recently published SPE Petroleum Resources Management System (PRMS) as a vehicle for business decision making, both in a regional context and in relation to other reserves protocols. Discussion throughout emphasized the interconnection between the process of estimating recoverable hydrocarbon volumes and the assessment of risk and uncertainty.
Mohd Jukris Abdul Wahab of Petronas, SPE Northern Asia Pacific Region director, gave the keynote address, which was followed by a presentation on PRMS by Geoff Barker, Resource Investment Strategy Consultants, who is an SPE Oil and Gas Reserves Committee member.
The first session was an Overview of Petroleum Resources and Reserves, keynoted by Yasin Senturk, Saudi Aramco. Among the challenges facing the industry, Senturk said, are the need for reliable reserves estimates and the reporting of those estimates within a harmonized system of definitions. But beyond this, he emphasized that the industry needs a systematic reserves-data management reporting and tracking system. PRMS is a key stage in the process, providing an update of the 1997 definitions that have already been promoted as standards in the oil and gas industry. The 2D PRMS scheme includes economic considerations on both the vertical axis (project maturity) and the horizontal axis (uncertainty), Senturk noted. Economics is separated from technical and project-maturity considerations in the overarching 3D United Nations Framework Classification (UNFC), he explained, and PRMS and other schemes can be mapped onto the UNFC. In this way, different schemes can be compared.
The ultimate goal, Senturk noted, is for PRMS to become a global standard, and an initiative is under way to produce guidelines for the implementation/application of PRMS. There is a worldwide effort to bring together different schemes for classifying reserves and resources. These ideas have been extended to estimating procedures and disclosure guidelines. The reserves-assessment process can draw upon deterministic and probabilistic methods, and these approaches are best used in combination, Senturk said.
Following the keynote address was a presentation by Amit Ashok Namjoshi, Inpex Browse, on Reserves Estimation of a Middle Eastern Waterflood.