bluuebunny/crossref_metadata_2025 huggingface dataset:
Potential for Additional CO2-Flood Projects in the US
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 113975, "The Potential for Additional Carbon Dioxide Flooding Projects in the United States," by Hitesh Mohan, SPE, Marshall Carolus, SPE, and Khosrow Biglarbigi, SPE, Intek, prepared for the 2008 SPE Improved Oil Recovery Symposium, Tulsa, 19-23 April. The paper has not been peer reviewed.

There is renewed interest in carbon dioxide enhanced oil recovery (CO2 EOR). Growing concern about climate change and greenhouse gases has increased interest in carbon capture and sequestration. CO2 EOR provides a value-added opportunity to increase crude-oil production while sequestering substantial volumes of industrial CO2. An analysis was conducted to determine the incremental domestic production that could be realized if industrially produced CO2 were available for EOR. Challenges include available volumes of CO2, infrastructure requirements, and prices of the CO2.

Introduction

US conventional crude-oil production continues to decline while demand for crude and finished products rises. According to the US Department of Energy Energy Information Administration (US DOE EIA) and shown in Fig. 1, the US demand will be greater than 27 million B/D by 2030, while total production will be less than 10 million B/D.

Four factors were identified that will have a significant effect on widespread implementation of CO2 EOR.Target resourceTechnologyAvailability of CO2Economics

Target Resource

There are 1,673 reservoirs onshore in the continental US that are candidates for CO2-miscible flooding. Fig. 2 shows the reservoirs that were identified on the basis of the following criteria.Gravity greater than 22°APIReservoir pressure greater than the minimum miscibility pressureDepth greater than 2,500 ftOil viscosity less than 10 cpCurrent oil saturation greater than 20%Either sandstone or carbonate rock

Technology

CO2-EOR technologies have been demonstrated to be profitable in commercial-scale applications for nearly 30 years. As of 2006, 80 CO2-EOR projects in the US had a combined production of 234,000 BOPD. Ten of these projects were started between 2004 and 2006. Of the projects active in 2006, 58 are in the Permian Basin. The reason is partly because of the prevalence of candidate reservoirs in that region, and because of the steady availability of natural CO2.
Technology Focus: Mature Field Revitalization (January 2009)
Authors: Ali Syed A.
Published: February 2015

Technology Focus

Even as new discoveries are developed and produced, substantial additional reserves can be secured by enhancing recovery from mature fields. Mature fields have the potential to contribute significantly to future reserves—provided that recovery can be optimized.

Usually, it is the new discoveries that capture the attention of the oil industry; however, 70% of the hydrocarbon liquids produced in the world today actually come from mature fields. With most of the world's potential oil provinces having already been explored and major new discoveries becoming increasingly rare, mature fields are destined to play an ever-more-prominent role in energy supply.

It is generally accepted that 30 to 35% of the original oil in place will be recoverable by the end of the normal production period. However, advances in technology (fueled by higher oil prices) are making it feasible to access remaining reserves. Considering the substantial quantities of remaining oil at stake, boosting the recovery factor on all the world's oil fields by a mere 1% would cover 3 years of worldwide consumption. Techniques to improve the recovery factor include: secondary- and tertiary-recovery schemes, horizontal and multilateral drilling, improved perforation and stimulation methods, new completion techniques, advanced logging procedures, and optimal placement of the new wells.

Mature fields, however, offer their own set of challenges. In addition to dealing with aging installations and earmarking investments to access additional reserves, all aspects must be considered carefully from a project-economics point of view. Water is another problem in reservoirs nearing the end of their production life; most oil companies produce far more water than oil, raising environmental concerns and water-handling expenses. Consequently, mature fields would require a strategy that is based on tapping bypassed oil, improving recovery from existing producing zones, cutting costs, and implementing leading-edge technologies to maximize production.

Mature Field Revitalization additional reading available at the SPE eLibrary: www.spe.org

SPE 113684 • "Mature-Field Rejuvenation of a Tight Gas Carbonate Utilizing Coiled-Tubing Underbalanced-Drilling Techniques" by C. Mykytiw, SPE, FX Solutions Group, et al.

SPE 113271 • "Techniques in Marginal and Mature Fields in the Pannonian Basin, Hungary: Case Study" by A. Holoda, MOL, et al.

SPE 112940 • "The Omar Field (NE Syria) Is Overcoming Its Mid-Life Crisis" by J. Neidhardt, Shell, et al.

SPE 112586 • "Horizontal Extended-Reach Re-Entry Drilling of Sidetracks at Sakhalin Island Increases Oil Production From Mature Oil Fields" by M.L. Drnec, SPE, Schlumberger, et al.
Comments (February 2004)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Q&A with Dato' Shamsul Azhar Abbas
Authors: Abbas Dato' Shamsul Azhar , Donnelly John
Published: February 2015

Q&A - No abstract available.
Techbits (February 2004)
Authors: JPT staff _
Published: February 2015

Techbits - No abstract available.
Overview: Drilling Technology (February 2004)
Authors: Kerbart Yves
Published: February 2015

Overview - No abstract available.
Drilling Technology: A Fully Automated System Accurately Controls Downhole Pressure During Drilling
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 85310, "Development and Testing of a Fully Automated System to Accurately Control Downhole Pressure During Drilling Operations," by E.J. van Riet and D. Reitsma, SPE, Shell Intl. E&P, and B. Vandecraen, IPCOS, prepared for the 2003 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Abu Dhabi, UAE, 20-22 October.
Offshore Facilities Construction and Design: Optimizing a Large-Vessel Separator Design for an FPSO in Bohai Bay
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 15356, "Optimizing a Large-Vessel Separator Design for FPSO Operation in Bohai Bay," by K.D. Durham and G.W. Sams, NATCO Group Inc., prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
Offshore Facilities Construction and Design: Increasing Load-Carrying Capacities of Offshore Foundations in Soft Clays
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15264, "A New Technology for Increasing the Load-Carrying Capacities of Offshore Foundations in Soft Clays," by S. Micic, Trow Consulting Engineers Ltd., and K.Y. Lo and J.Q. Shang, Geotechnical Research Centre, U. of Western Ontario, prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
Overview: Well Testing (February 2004)
Authors: Stratton Jay
Published: February 2015

Overview - No abstract available.
Well Testing: Will Wireline Formation Tests Replace Well Tests?
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84086, "Will Wireline Formation Tests Replace Well Tests?," by T.M. Whittle, SPE, and J. Lee, SPE, Baker Atlas, and A.C. Gringarten, SPE, Imperial College, U.K., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Techbits (February 2005)
Authors: JPT staff _
Published: February 2015

The importance of interpreting and applying right decisions in data management and technology development in Central and Eastern European fields was the focus of the Applied Technology Workshop (ATW) “Field Management of Mature Reservoirs” held in Vienna, Austria. Through presentations, case studies, and syndicate sessions, participants conferred on the following topics:

- Accessing data and discovering the value of mature reservoirs.

- Recognizing existing technologies that can be applied success-fully in mature reservoirs.

- Tools to unlock value in mature assets.

- How future technologies will affect mature assets.

- From today’s reality to tomorrow’s dream as described by E&P and service company senior management.

Good reservoir review, field management, and using the right technologies were considered in the first technical session. Particular emphasis was placed on the importance of standards, change management, documentation of a good track record in conjunction with business processes, and collaboration with people. The fact that a significant amount of data can no longer be read or accessed as a result of changes in asset management was also addressed.

The second session highlighted case histories that illustrated how existing technologies provided correct solutions in alignment with best practices in Central Europe’s Mesozoic formations and in the Carpathian range. The session was devoted to proving that right understanding of mature-reservoir problems must exist in advance to select proper technologies for application. When the right degree of understanding exists, a substantial number of existing methods and equipment is available for use in mature reservoirs.

The impact of differing stakeholder perspectives and requirements on the management of mature E&P assets was presented in the third technical session. Steve Mills from the Royal Bank of Scotland presented the investor’s point of view toward the materializing process and the importance of selecting the proper investment plan. Beate Raabe of the Intl. Assn. of Oil and Gas Producers presented the European Union administrative viewpoint regarding development of mature assets and taking into account future regulatory requirements. Representatives from Wintershall A.G. and Industrija Nafte d.d. presented company strategies for development of mature fields as part of an asset portfolio and showed how these fields still can offer attractive options for E&P companies.
Educating the Next Generation of Engineers
Authors: Langley Diane
Published: February 2015

Lifelong learning is a prominent issue currently on the minds of educators and employers, as illustrated in discussions during the SPE Sixth Colloquium on Petroleum Engineering Education (CPEE 2004). Lifelong learning, the focus of this colloquium, includes developing learning skills while in college and continuing education of engineers beyond college. Working together to build a stronger educational experience for petroleum engineers, academics, and employers identified the technical and personal strengths being required of engineers by industry and began to implement several action items to communicate the evolving educational roles of academia, industry, the service sector, government, and SPE.

The 49 session participants—representing academia, industry, and the service sector—met for 3 days in August 2004 at the Colorado School of Mines in Golden, Colorado, to enhance under-standing of industry education needs and to discuss how universities—in partnership with industry, service companies, and government—can help fill those needs.

Qualifying the Graduate Engineer

Assessment of technical and personal qualifications of recently graduated engineers, the establishment and global acceptance of certification standards, a look at innovative teaching programs, and information gleaned from a survey of young energy professionals were topics highlighted in five Colloquium sessions. The session titled “From Emerging Graduate to Emerging Leader” focused on the viewpoints and expectations of employers, recent graduates, and academics. Brice Peterson of Shell, Larry Schwartz of Schlumberger, Julie Struble of Anadarko, and Ganesh Thakur of ChevronTexaco examined their respective current viewpoints and expectations as engineering employers. From the industry perspective, some of the skills and attributes that recruiters seek in new hires are effective communication and teamwork abilities, analytical and problem-solving skills, judgment and decision-making capabilities, adaptability, initiative and motivation, all in addition to technical and professional knowledge.
High-Performance Slimhole Drilling With 4-in. Drillpipe and a Streamline Connection
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87988, "High-Performance, Slimhole Drilling With 4-in. Drillpipe and a Streamline Connection," by Guillaume J. Plessis, SPE, Grant Prideco; Andre Glowacz, Total; John M. Pasnak, SPE, Saudi Aramco; and Michael J. Jellison, SPE, Grant Prideco, prepared for the 2004 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Kuala Lumpur, 13-15 September.

Saudi Aramco and Total Indonesia used 4-in. drillpipe with streamlined double-shoulder connections to drill wells for which 3 1/2-in. drillpipe was unsuitable. The 4-in. drillpipe with enhanced torsional, tensile, and hydraulic characteristics was used to drill longer slimholes at a lower overall cost. The selected double-shoulder connection has an outside diameter (OD) similar to standard 3 1/2-in.-drillpipe tool joints while maintaining the fishability of the 4-in. pipe in casing and open hole. The stream-line-connection design provides 22,000 ft-lbf of working torque, a 4 7/8-in. OD, and an oversized internal bore that promotes hydraulic efficiency.

Introduction

Drilling deeper slimhole wells has revealed limitations of the 3 1/2-in. drillpipe traditionally used to drill the 6- to 6 1/4-in. hole sections. The torque level that American Petroleum Inst. (API) rotary shoulder and first-generation double-shoulder connections can deliver does not match the new requirements for these deeper drilling programs. The increase in drillstring length also imposes an addition-al constraint on hydraulic performance.
Targeted Development of Low-Cost 3D Rotary-Steerable Systems
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87165, "An Operator's Targeted Development of Low-Cost 3D Rotary-Steerable Systems," by J.T. Travis Jr., SPE, J.H. Moss, SPE, and G.M. Browning, SPE, ExxonMobil Development Co., prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.

The many benefits of 3D rotary-steering systems (RSSs) are well documented. ExxonMobil Development Co. (EMDC) Drilling continues to expand its use of 3D RSSs in its daily drilling operations. Its drilling operations include a variety of well architectures in both the high-cost and low-cost markets. Because of the high price of RSSs currently on the market, EMDC is unable to justify use of these systems in lower-cost wells. However, the low-cost market would benefit from the higher rates of penetration (ROPs), reduced risk through improved hole cleaning, reduced wellbore tortuosity, and more-efficient directional control.

Introduction

Three-dimensional RSSs currently are being deployed in approximately 5% of EMDC’s daily rig operations. Very high spread costs and/or well profiles beyond the capabilities of conventional directional-drilling methods usually justify these applications. Spread costs are defined as the daily operating cost less tangible items such as tubulars, wellheads, and completions equipment. The costs of high-cost floating-drilling, platform, and deep-remote land wells range from U.S. $100,000/day to U.S.$500,000/day. Normal land operations average only U.S. $15,000/day.

As experience was gained, it become apparent to the drilling organization that there was a large well inventory in need of the benefits of a 3D RSS that cannot currently justify its application economically.

The initial 3D RSS providers’ market was, and in most cases still is, a higher-operating-cost environment that does not fit lower-cost market needs. The high-cost environment needs only a 10% improvement to justify a 3D RSS, whereas the low-cost environment would require approximately 100% improvement to justify a 3D RSS. The high prices charged for these first systems are driven by the following.
Overview: Offshore Facilities Construction and Design (February 2005)
Authors: Valenchon Claude
Published: February 2015

Liquefied natural gas (LNG) and offshore activities have much in common.

- The ultimate goal of each is to produce and deliver hydrocarbons to the market.

- The main oil operators are active in LNG as well as other offshore activities (e.g., ExxonMobil, Shell, BP, Total, and ChevronTexaco).

- Production is transported over long distances by carriers (even if LNG carriers are far more sophisticated than oil tankers!).

But, until now, LNG production plants have always been built onshore, even when gas is produced offshore (e.g., Qatar, Trinidad, and Sakhalin). The first concepts of LNG floating production, storage, and offloading (FPSO) vessels were presented by the industry in the mid-1970s. These concepts were targeting stand-alone gasfield developments or associated gas fields.

Even if an LNG FPSO appears economically very attractive when compared with a “grass roots” onshore LNG plant, the operators seem not to have found the proper location or the correct “scheme” to select an LNG FPSO for developing an offshore gas field. At the other end of the LNG chain, huge investments also are foreseen to build facilities for the reception and regasification of LNG to cope with a fast-growing demand for gas.

Many terminals are under construction or planned in many countries. This increased demand is not without obstacles. In some areas of North America or Europe (Italy for example), environmental constraints prevent the installation of newly built, land-based LNG terminals. As a result, the projects are moving offshore, taking the shape of fixed, gravity-based structures or floating storage and regasification units.

In this offshore move of the LNG industry—“tomorrow” for the receiving terminals and the “day after tomorrow” for LNG FPSOs—those who combine LNG and offshore expertise will be key players in this new arena.

Additional Offshore Facilities Construction and Design Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 89998 - Subsea HIPPS: A Way To Develop High-Pressure Subsea Fields

Available at the OTC Library: www.otcnet.org

OTC 16106 - Monitoring of Sand Deposition in Subsea Separators

OTC 16185 - High-Strength Aluminum Alloys for Deepwater Riser Applications
Spar Vortex-Induced-Vibration Prediction
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 16343, "Advancement of Spar VIV Prediction," by T.-W. Yung, R.E. Sandstrom, S.T. Slocum, Z.J. Ding, and R.T. Lokken, SPE, ExxonMobil Upstream Research Co., originally presented at the 2004 Offshore Technology Conference, Houston, 3-6 May.

Vortex-induced vibration (VIV) of spar hulls is an operational issue in high-current environments and an important consideration for mooring and riser integrity. On the basis of extensive analytical, laboratory, and field studies, ExxonMobil has developed a reliable methodology for predicting the VIV of classic spars that has been validated by field measurements.

Introduction

Spar technology continues to evolve and currently is experiencing wide application in deep- to ultradeepwater fields in the Gulf of Mexico (GOM). Eight spars have been installed in the GOM since 1996, and five more are in various stages of design and construction. These include classic spars [deep-draft caisson vessel (DDCV)], truss spars, and cell spars. A spar platform is characterized by a large, usually cylindrical, hull that extends deep into the water.

In the GOM, the loop current and loop-current eddies (Fig. 1) have the potential to cause VIV on the spar hull. Speeds in these currents can remain high well below the surface, exposing the entire hull to large forces. In addition, hurricane currents also may cause VIV spar motion. Field measurements have shown that all of the three classic spars (Hoover, Genesis, and Neptune) have experienced VIV. From these experiences, it was observed that both loop/eddy currents and inertial currents (after a severe storm) could cause VIV. For the Hoover DDCV, eddy currents with speeds as low as 1 to 2 knots have caused VIV.

Industrial experience with VIV started many decades ago with the development of VIV-suppression devices for smokestacks and chimneys. Over the years, there have been numerous studies on VIV physics as well as VIV-suppression devices for onshore and offshore structures. In recent years, there has been an increased interest in spar-VIV-design practice, highlighted by the first-ever industrywide workshop dedicated exclusively to spar VIV. The October 2003 workshop addressed a wide range of topics. In the workshop, the ExxonMobil spar VIV-design practice, based on work for the Hoover project, was presented. The design practice is based on a combined analytical, model-testing, and field-measurement approach. The discussion was focused on key factors for reliable prediction of classic-spar hull-VIV response and comparisons between model test results and field measurements.
Overview: Well Testing (February 2005)
Authors: Stratton Jay
Published: February 2015

The industry spends millions of dollars to achieve success in reaching the target objectives for an exploration well. Even with impressive petrophysical data, the well-test information will determine the potential commerciality of the exploration project. Similarly, in the production environment, reservoir descriptions that are always more complex than idealized reservoir models present unique challenges to the accurate char still can arrive at valid yet surprisingly different conclusions from the same well-test analysis. Even with current advances in technology, there is no replacing the sound engineering judgment necessary for analysis of a complete set of well-test data.

Our industry continues to seek improved and innovative methods of improving our well-test data-gathering and -analysis methods. Accuracy of the pressure/volume/temperature data is fundamental to the well-test analysis, and errors in this input will compromise the final analysis. Numerical methods that more accurately describe reservoir conditions during testing will allow modeling of more-complex descriptions. Tools to allow earlier and more accurate analysis of reservoir fluids and rock properties accelerate our understanding of a new prospect and can save time and cost of unnecessary delays in analysis and completion recommendations. Real-time production monitoring of wells can lower the cost of gathering ongoing well-test data and improve our understanding of the reservoir relative to infrequent snapshots of data common to most projects.

Advances are being made in all the components of well-test-analysis technology. Fluid-sampling and -analysis tools; well-test-analysis software; and pressure-, temperature-, and rate-monitoring technology are improving. Reservoir models are adapting to more-complex environments. Artificial intelligence is used in efforts to discern accurate well-test-analysis results with less applied-engineering judgment. However, with increased technology, a flood of additional data and models are available from which a rigorous engineering analysis must be completed. Engineering judgment with assistance of the technical capabilities of an entire multidisciplinary team is still the most critical component needed to determine the unique solution that will most accurately complete a reservoir and well description. The following pages provide examples of the broad range of reservoir information being gathered, analyzed, and managed to make the exploitation of hydrocarbon resources more efficient and profitable.

Additional Well Testing Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 90236 - Uncertainties in Standard Analyses of Boundary Effects in Buildup Data

SPE 90960 - Simultaneous Estimation of In-Situ Multiphase Petrophysical Properties of Rock Formations From Wireline-Formation-Tester and Induction-Logging Measurements

SPE 92041 - Grid-System Requirements in Numerical Modeling of Pressure-Transient Tests in Horizontal Wells
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.