bluuebunny/crossref_metadata_2025 huggingface dataset:
Top 10 Risks for the Oil and Gas Industry
Authors: Jessen Rob
Published: February 2015

Guest editorial

Risks are inherent in every forward-looking business decision. As a result, there has been a great deal of work done and resources invested in risk management in the oil and gas industry in recent years. Financial and regulatory risks have been the focus of much of this effort. But more recently, companies have started including operational risks, prioritizing them and thinking about how they can manage and monitor all risks in a coordinated way.

In collaboration with Oxford Analytica, Ernst & Young examined the strategic risks facing oil and gas companies. This study was not a random selection exercise but rather a structured consultation with industry leaders and subject matter professionals from around the world (Fig. 1). What follows are the top 10 identified strategic risks for oil and gas companies.

1. Human Capital Deficit

The growing human capital deficit in the sector has become a significant strategic threat to the industry. One study participant set out the issue: "The ability of the oil and gas services sector to expand sufficiently to meet future demand growth is questionable, not least in terms of staff. Project delays and abandonment are as much a result of capacity constraints as financial calculations, although the two are intimately linked."

2. Worsening Fiscal Terms

Worsening fiscal terms are seen as a high risk. In some cases, this is due to energy nationalism, although in others it is purely the result of political opportunism and high prices. Tax regime changes can spur additional oil and gas industry restructuring in countries such as Canada, Venezuela, Russia, and Algeria. The impact of political opportunism and high prices is a device that has been seen in both the developing and nondeveloping world.

3. Cost Controls

The third operational threat is the inability to control costs. This threat was considered great enough to have a strategic impact, and a failure to manage the threat could undermine the competitiveness of oil and gas companies. Participants agreed that the problem extends from exploration all the way through the value chain, impacting everything from refinery build costs to pipeline construction. The Upstream Capital Costs Index, which measures cost inflation in oil and gas projects, has gone up by 79% since 2000, with most of that increase coming since May 2005.
Improved UOE Pipe-Manufacturing Process Helps Meet Deepwater Pipeline Challenges
Authors: JPT staff _
Published: February 2015

Technology Update

Conventional pipeline design, although concerned with many factors, generally centers on the need to withstand the internal pressure in the line. The higher the pressure at which throughput can flow, the higher the flow rate, and the greater the revenue potential for the operator. However, when considering the factors critical for deepwater pipelines, much of the focus shifts to the need to withstand the external pressure on the line, particularly during installation.

With local "infield" lines, such as subsea umbilicals, risers, and flowlines, the challenge is modest because the lines are small in diameter and, thus, inherently resistant to hydrostatic collapse. These lines are generally produced as seamless pipe, which in smaller sizes is readily available and generally a suitable economic solution.

However, deepwater trunklines, especially with long-distance tiebacks, present a greater challenge. These lines must be wider in diameter to meet the production demands of large-scale, high-cost projects. Thicker pipe wall is required to ensure that pipes can withstand the hydrostatic pressure and bending that affect them as they are laid to the seabed. Often, these are 16- to 20-in.-diameter lines, which places them at the economic limit for seamless pipe production methods. A project table including some typical deepwater pipe properties is shown in Fig. 1.

It is possible to produce thick-walled, seamless pipe at these diameters by means of the Pilger process, in which hot round steel billets that have been hollowed in the initial phase of production are rolled and stretched until the desired length and diameter are achieved. However, the manufacturing process is slow and the cost of material high.

The most economic method of manufacturing pipe at these wall thicknesses and diameters is the UOE process, in which steel plate is pressed into a U and then an O shape and then is expanded circumferentially. (This process was used in the projects shown in Fig. 1.) The advantages of the UOE process notwithstanding, the current wall-thickness and diameter requirements for deepwater trunkline pipe still have proved challenging from the standpoint of manufacturing economics and installation capabilities. Only a handful of manufacturers are capable of supplying double-submerged, arc-welded (DSAW) pipe that meets specifications for the deepest projects, such as the Shell Perdido development in the Gulf of Mexico.

The acceptability of a pipeline design for a given water depth is determined by means of standard equations that measure the relationship between outside diameter, wall thickness, pipe shape, and material compressive strength.
Coalbed-Methane Pilots: Timing, Design, and Analysis
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 114169, "Coalbed-Methane Pilots: Timing, Design, and Analysis," by R.D. Roadifer, SPE, ConocoPhillips Alaska, and T.R. Moore, CDX Gas, prepared for the 2008 SPE Unconventional Reservoirs Conference, Keystone, Colorado, 10–12 February. The paper has not been peer reviewed.

Four distinct, sequential phases form a recommended process for coalbed-methane (CBM) -prospect assessment: initial screening, reconnaissance, pilot testing, and final appraisal. A step-wise approach through these phases provides a program of progressively ramping work and cost, while creating a series of discrete decision points at which analysis of results and risks can be assessed. The focus here is on the third phase, pilot testing, which normally takes place after reconnaissance and before final appraisal.

Introduction

CBM gas accounts for 9% of US domestic natural-gas production. Its importance to the energy industry has grown dramatically in the past 20 years. CBM production is expected to continue to grow significantly over the next decade, both in the US and internationally.

Historically, the CBM opportunity-identification and -evaluation process has taken place in an ad hoc, almost happenstance manner. There is no comprehensive model for planning the exploration and evaluation of a CBM play. Several authors have detailed individual phases of the assessment process for CBM, while touching on assessment process only briefly. The aim of this paper is to develop a consistent approach to evaluating CBM opportunities (i.e., pilot testing).

A stepwise phased CBM-prospect-assessment process enables gaining local knowledge early at low cost; progressively acquiring appropriate data to assess the geological situation and reservoir conditions systematically; defining and attempting to fill knowledge gaps that represent risk and uncertainty; increasing understanding of the distributions of key parameters that control reserves, deliverability, and value; and staging expenditures and providing multiple decision points throughout the process. In the initial-screening phase, the broad basin, trend, or play is considered. The scope of investigation is narrowed and knowledge is high-graded to define a play- or lead-scale area of interest. Some sort of acreage position is obtained on that play or lead, enabling the acquisition of hard data on the coal quality and reservoir characteristics by drilling a small number of dispersed reconnaissance core holes. A favorable reconnaissance program provides justification for a CBM exploration pilot test on the prospect. The pilot test serves the same function as a conventional exploration well such that if it proves successful, then the prospect can be considered to be a discovery.
A Monitoring and Verification Plan for The Otway CO2 Pilot Project
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19202, "Developing a Monitoring and Verification Plan With Reference to the Australian Otway CO2 Pilot Project," by Kevin Dodds, SPE, CSIRO, and Sandeep Sharma, SPE, Schlumberger, originally prepared for the 2008 Offshore Technology Conference, Houston, 5–8 May. The paper has not been peer reviewed.

The Australian Cooperative Research Center for Greenhouse Gas Technologies (CO2CRC) currently is injecting 100,000 tons of CO2 in a large-scale test of storage technology in a pilot project in southeastern Australia called the CO2CRC Otway Basin Project (Otway). The Otway basin with its natural CO2 accumulations and many depleted gas fields, offers an appropriate site for such a pilot project. An 80% CO2 stream is produced from a well near the depleted gas reservoir used for storage. The goal of this pilot project is to demonstrate that CO2 can be transported and stored underground safely and its behavior tracked and monitored.

Introduction

The commercial oil and gas leases in the Otway basin in Victoria, selected for the pilot project, are in an undeveloped CO2 field (Buttress), which is the source of CO2, and a depleted gas reservoir (Naylor), which is the injection/containment site. The extracted and separated CO2 stream is transported by pipeline and injected into a new well (CRC-1), drilled downdip of the existing well, and into the depleted Waarre reservoir in the Naylor field at a depth of approximately 2000 m. The existing shut-in production well (Naylor-1) is being used as the monitoring well. Characterization of the site has involved the collection of a large quantity of geological, geophysical, and other regionally relevant data and the construction of static and dynamic reservoir models. The regional formations provide an excellent porous and permeable geological formation that provides a highly suitable reservoir system for CO2 storage. In summary, the site-assessment results, indicating that the Waarre formation is a suitable site for CO2 storage, conclude the following key attributes of the site. There are no significant faults evident in the wells at the Waarre C level; there is a fairly uniform Waarre C thickness. The local and regional seals have contained a number of natural CO2 accumulations in the eastern Otway basin over geological time. The storage reservoir has sufficient porosity and permeability to be able to accept the injected CO2 at forecast rates. The injected CO2 is predicted to move updip from the injector location and migrate to the crest of the fault block and accumulate below the residual-methane gas cap in the vicinity of the existing Naylor-1 well. The selected site has the major advantage of being onshore rather than offshore, allowing the project research teams to test and further refine the monitoring and verification techniques at a more accessible location.
Technology Focus: Artificial Lift (July 2009)
Authors: Noonan Shauna
Published: February 2015

Technology Focus

Artificial-lift technology has been around for many years, yet the concept of artificial-lift selection and design has been more of an art than a science. Throughout the last decade, both operating companies and manufacturers have made considerable effort toward understanding the science behind artificial-lift systems and their performance. For example, research on beam-pump slippage and gas lift valve performance has greatly influenced the way in which the industry now designs those lift systems. In 2007, SPE published a revised Petroleum Engineering Handbook; Volume IV includes many of these advancements and understandings of lift performance for common forms of artificial lift. This publication is recommended highly for anyone involved in production engineering and artificial lift.

Artificial-lift systems continue to evolve, and their operational envelopes expand. The 2009 ATCE Technical Program Committee received a significant number of artificial-lift related abstracts, which resulted in two sessions showcasing great artificial-lift research, field trials, and case studies. When you come to New Orleans this October, you will learn about the most recent advancements and lessons learned on all types of artificial lift.

Three examples of such advancements are featured in this publication. Each of these technologies enhances a lift system or methodology that has been available for years, putting a new spin (pun intended) on something "old." While the field trials of these systems have been specific to a given region (i.e., Alaska, Cuba, and Russia), their application potential is global.

The papers selected for additional reading below, reflect other areas in the artificial-lift community that are "hot" topics—finding and understanding better gaswell-deliquification techniques, solutions to high-volume thermal applications, and effective artificial-lift optimization.

Artificial Lift additional reading available at OnePetro: www.onepetro.org

SPE 116659 - "Artificial Lift Optimization in the Orito Field" by Sandy Williams, SPE, ALP Ltd., et al.

SPE 115849 - "Pushing the Limit: High-Rate Artificial-Lift Evaluation for a Sour, Heavy-Oil, Thermal EOR Project in Oman" by G.H. Lanier, SPE, Petroleum Development Oman, et al.

SPE 115934 - "Development of a New Plunger-Lift Model Using Smart Plunger Data" by G.K. Chava, SPE, Texas A&M University, et al.
Experience With Metal PCPs in a Cuban Heavy-Oil Field
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120645, "Field- Implementation Experience With Metal- PCP Technology in Cuban Heavy-Oil Fields," by E. Guerra, SPE, and A. Sanchez, SPE, Sherritt International Oil and Gas, and C. Matthews, SPE, C-FER Technologies, originally prepared for the 2009 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 4-8 April. The paper has not been peer reviewed.

Progressing-cavity pumps (PCPs) have proved to be a successful and reliable artificial-lift system for production of heavy oil over the past few decades. The application of PCP technology for production of oil wells continues to expand rapidly because of ongoing advances in versatility, lift capacity, durability, and economy. As a result, the application envelope for PCP systems has grown substantially to the point where these systems now compete successfully in many areas that were traditionally reserved for rod- and electrical-submersible-pump technologies.

Introduction

PCPs have found numerous applications in many industries as an efficient means to transfer, transport, and/or lift fluids of a diverse nature. The use of PCPs as an artificial-lift method for oil wells has gained increasing acceptance since their first commercial use in heavy-oil applications in the 1980s, and they have now become the preferred lift method in numerous oilfield developments worldwide.

PCP Systems

A typical PCP consists of two basic components: the first is called the stator—it is typically run on the end of the production-tubing string and remains stationary during operation; the second is called the rotor—it is run on the end of a sucker-rod string and rotates within the fixed stator when in operation. The elongated steel rotor is machined with a circular cross section and a uniform helix with a prescribed eccentricity and pitch length. Rotors are normally chrome coated to reduce friction and improve wear resistance in service. The stator cavity takes the form of a double internal helix with a pitch length that is double that of the rotor—with the rotor installed, this configuration creates two series of parallel cavities within the pump that are filled by produced fluid. As the rotor spins within the stator through the application of torque to the rod string at surface, wellbore fluid is drawn into the pump and is displaced from the intake through the cavities along the stator to the discharge where it exits at high pressure into the production-tubing string.
Development of Natural-Gas Supply Chain by Means of Natural-Gas Hydrates
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12880, "Development of Natural Gas Supply Chain by Means of Natural-Gas Hydrate (NGH)," by Tomonori Nogami and Shigeru Watanabe, Mitsui Engineering & Shipbuilding, originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.

Because natural-gas hydrates (NGHs) can be stabilized at 253 K and are easy to handle, NGHs are expected to be an alternative natural-gas transportation medium to the currently available systems including liquefied natural gas (LNG). A joint industry and government project has been initiated to demonstrate the feasibility of natural-gas land transport and ocean transport in the form of NGH.

Introduction

Since the idea of ocean transportation of natural gas in the form of NGH was advocated by J. S. Gudmundsson of the Norwegian University of Science and Technology in 1996, various research on NGH ocean transportation has been performed. A test plant for NGH production has been built in the US. One company has been conducting research and development on the NGH-production process, a carrier ship, and the regasification process since 2001. A new conceptual design has been developed for a process development unit (PDU).

NGH Process Developments

Mitsui Engineering & Shipbuilding succeeded in producing NGH continuously at a high speed in March 2001, and in September of that year they started research and development of NGH in full scale to commercialize the NGH process. In January 2002, a continuous-production plant was completed that produced NGH pellets, and in 2003 a regasification facility was added. These facilities began operation as the first-stage PDU (Fig. 1) with a 600-kg/d NGH-pellet production capacity. This plant can produce high-purity NGH pellets at a high speed continuously. Feed gas is contacted with water, causing a reaction that generates NGH, followed by dewatering and cooling. The PDU made it possible to operate a circuit process. NGH pellets are made of the powder produced in the process and then are regasified to natural gas to recycle in the plant.

In 2005, a second-stage NGH-production plant called a bench-scale unit (BSU) (Fig. 2) was completed. Although NGH production from mixed gas had seemed difficult to realize, artificial production of NGH succeeded at the BSU. Fig. 3 shows NGH pellets produced by the BSU in the pellet-storage drum. As an experiment of NGH land transportation, NGH pellets were transported 350 km to a 2005 World Exposition.
Technology Focus: CO2 Applications (July 2009)
Authors: Gomersall Sam
Published: February 2015

Technology Focus

Can enhanced oil recovery (EOR) contribute to CO2 abatement as part of a climate-change-mitigation program?

EOR by use of CO2 is an important technique for increasing oil recovery. Carbon capture and storage (CCS) will be an increasingly important technique for reducing atmospheric emissions of CO2 as part of a climate-change-mitigation program. What role does EOR have in reducing CO2 emissions to the atmosphere and in supporting climate-change mitigation?

It is clear that the two processes have very different objectives: EOR focuses on maximizing the amount of oil recovered, whereas CCS focuses on sequestration of CO2 for the long term.

Most existing EOR projects use naturally occurring CO2, produced from subsurface traps especially for EOR. Rather than mitigating emissions, these projects contribute to global CO2 emissions. Clearly, this situation is not good for the climate.

Other emerging EOR projects and future projects could use anthropogenic CO2 (i.e., CO2 from industrial sources). When the CO2 associated with the use of the EOR oil is taken into account along with the processing and emissions from CO2 recycling, EOR is a significant producer of greenhouse gas and not a CO2-abatement technique.

However, EOR oil does have a lower emissions intensity than non-EOR oil, assuming that the CO2 is from anthropogenic sources. It would be much better, for example, to produce a barrel of EOR oil than a barrel of oil from oil sands.

EOR has an important role to play in energy security, but from a global-climate perspective, it is not a CO2-abatement technique.

CO2 Applications additional reading available at OnePetro: www.onepetro.org

SPE 116661 • "Optimizing Injection Intervals in Vertical and Horizontal Wells for CO2 Sequestration" by Navanit Kumar, SPE, University of Texas at Austin, et al.

SPE 119747 • "Thermodynamic Criteria and Final Results of WAG CO2 Injection in a Pilot Project in Croatia" by D. Novosel, INA-Naftaplin

SPE 114553 • "Produced CO2 Storage Into Aquifer in an Offshore Field, Malaysia" by Dewanto Odeara Kartikasurja, SPE, Senergy Ltd.
Comments (August 2004)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
The Importance of Being Value Driven
Authors: Sinor Allen
Published: February 2015

Guest editorial - No abstract available.
Techbits: Research Symposium Focuses on Complexity of Carbonate-Reservoir Characterization and Simulation
Authors: Feazel Charles , Byrnes Alan , Honefenger James , Leibrecht Robert , Loucks Robert , McCants Steven , Saller Art
Published: February 2015

Geoscientists and reservoir engineers exploring for, or producing from, oil and gas reservoirs commonly face the tasks of converting conceptual geological models to numerical geocellular models and upscaling fine-scale models to coarser grids for fluid-flow simulation. Many factors—like heterogeneous stratal architectures, the presence and role of fractures, and multistage diagenetic histories that create complex pore networks—complicate this process in carbonate reservoirs. The resulting reservoir models are used to make economic decisions, some involving billions of dollars, at many points in the lifetime of an asset, from acreage acquisition to wellpath optimization, injection design, or production cessation. When such models are constructed and populated, varying amounts of hard data may be available: in the earliest stages, model builders may be working with exploratory seismic surveys and predrill analyses based largely on analogs. When dealing with mature fields, geomodelers may have the luxury of data from hundreds of wells, several decades of production history, and 3D or 4D seismic volumes, but may have the limitation of older wireline logs.
Interface Management Improves On-Time, On-Budget Delivery of Megaprojects
Authors: Nooteboom Uri
Published: February 2015

Management - No abstract available.
Microseismic Fracture Mapping Using Perforation-Timing Measurements for Velocity Calibration
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84488, "Improved Microseismic Fracture Mapping Using Perforation-Timing Measurements for Velocity Calibration," by N.R. Warpinski, SPE, Sandia Natl. Laboratories; R.B. Sullivan, SPE, Anadarko Petroleum Corp.; J.E. Uhl, Sandia Natl. Laboratories; and C.K. Waltman, SPE, and S.R. Machovoe, SPE, Pinnacle Technologies, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Reservoir Models Built With 4D-Seismic and Well Data
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84370, "Building Reservoir Models Based on 4D-Seismic and Well Data in Gulf of Mexico Oil Fields," by Catherine Bogan, SPE, Daniel Johnson, SPE, Michael Litvak, SPE, and Doug Stauber, BP plc, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Assessing Scale Risks and Uncertainties for Subsea Marginal-Field Development
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87460, "Assessing Scale Risks and Uncertainties for Subsea Marginal-Field Developments," by G.M. Graham, SPE, Scaled Solutions Ltd., and I.R. Collins, SPE, BP Ltd., prepared for the 2004 SPE International Symposium on Oilfield Scale, Aberdeen, 26-27 May.
An Assessment of Subsea Production Systems
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84045, "An Assessment of Subsea Production Systems," by D. Devegowda, SPE, and S.L. Scott, SPE, Texas A&M U., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Overview: Cementing Technology (August 2004)
Authors: Benge Glen
Published: February 2015

Overview - No abstract available.
Simulation of Collapse Loads on Cemented Casing
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84566, "Simulation of Collapse Loads on Cemented Casing Using Finite-Element Analysis," by W.J. Rodriguez, SPE, PDVSA Intevep, and W.W. Fleckenstein, SPE, and A.W. Eustes, SPE, Colorado School of Mines, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Through-Tubing Rotary Drilling and Its Cementing Challenges
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 83955, "Through-Tubing Rotary Drilling and Its Associated Cementing Challenges: A North Sea Experience," by Joao G.R. Queiros, SPE, Benoit Vidick, SPE, and Jamie Cochran, Schlumberger, and Joy S. Oyovwevotu, SPE, Leading Edge Advantage, prepared for the 2003 Offshore Europe, Aberdeen, 2-5 September.
Comments: JPT Reader Survey
Authors: Donnelly John
Published: February 2015

In May, JPT surveyed SPE members to get their assessment of this magazine and their suggestions for ways to improve it and make it more relevant to them. The online survey was sent to a random sample of members worldwide. Of the respondents, one-third were from the U.S. and two-thirds outside the U.S.; half were engineers, and a quarter were managers; and 32% work for service companies and manufacturers, while 21% work for international oil companies, 19% for independents, and 7% for national oil companies. To the more than 2,000 members who responded, thank you for taking the trouble to complete the survey. It will help us do a better job of giving you the information you need in your work and in your careers.

Now, to the findings. The overall content of JPT was rated “good” to “excellent” by 95% of the survey respondents. This is slightly higher than the feedback we received in our most recent reader survey 2 years ago. JPT is considered to be “useful in their jobs” by 88% of readers; again, a little higher ranking than the previous survey. Employees at national oil companies find the information most useful.

The most popular features in the magazine, in order, are Technology Update, Technology Applications, the summaries of the technical papers, and the quarterly Case Study feature. The Case Study article was added after the 2003 survey found that our readers wanted more case study and practical application information. The most popular technical topics, in order, are: field development; high-pressure/high-temperature challenges; multilateral/extended reach; mature field revitalization; well stimulation; horizontal and complex trajectory wells; reservoir performance and monitoring; formation evaluation; production operations; and well testing. The most favored nontechnical topics include career development articles, compensation and salary surveys, project management information, industry software reviews, and oil and gas industry politics.
Techbits: Drivers of Deepwater Development in the Asia Pacific Region
Authors: JPT staff _
Published: February 2015

Ramlan Malek, Petronas General Manager—Petroleum Management Unit, and Ricardo Beltrao, Petrobras General Manager, set the stage for discussion among 78 participants representing numerous countries at the SPE Applied Technology Workshop (ATW) “Managing Deepwater in the Asia Pacific Region.” Held in Bangkok, Thailand, the ATW featured two keynote speakers: Malek on “Challenges in Managing Deepwater Field Development in Malaysia” and Beltrao on “New Technologies for Field Development in 3000-m Water Depths.”

Water depth in the Asia Pacific Region is defined as follows.

- Shallow water—depth less than 200 m.

- Deep water—depth greater than 200 m but less than 1000 m.

- Ultradeep water—depth greater than 1000 m.

Highlighting some successful deepwater operations/development projects in the region and future projects on the horizon including Unocal’s Gendalo Subsea, Shell’s Gumusut/Kakap and Malikai, and some China Natl. Offshore Oil Corp. (CNOOC) ventures, production in the Asia Pacific Region will increase 60% by 2020, with most of the energy resources coming to production from deepwater assets. The challenge will be to develop these projects reliably, affordably, and in a timely manner, requiring close cooperation among host authorities, oil companies, and service providers. Speakers noted that a paradigm shift in mindset is needed to accommodate current operating experience in shallow water to the new potential deepwater environment. Commentary called for investment portfolios to be reshaped to address the need for technical proficiency and for efficient operations requiring a highly focused group to develop, build, and integrate deepwater business.

The topic of “value erosion” in gas-handling projects and the industry’s need to invent and apply novel market solutions were other pertinent topics on which speakers and audience members presented their views. Also, cost reduction in Asia Pacific’s deepwater projects will come from the impact of new technology. While much of the technology is remotely operated, people will have a significant impact on how that technology is leveraged and in combining these technologies to create full-life-cycle savings.

In addition to exploring the different corporate strategies for managing deepwater field development and operating experiences of the various regional operators, such as Shell in the Philippines, Unocal in Indonesia, and Petronas in Malaysia, the workshop focused on technical and commercial challenges. Participants conferred on eight technical challenges, from obtaining accurate metocean data for design development to geohazards.
Overview: Cementing Technology (August 2005)
Authors: Benge Glen
Published: February 2015

If only we knew.

Did we do it right? Did we get the results we wanted? These simple questions have been difficult to answer for cementing since the first job was pumped. We usually can tell when things did not go as planned. Proving we got it right is an entirely different matter.

There are many methods and tools available to try to prove the job actually gave the desired results.

We can evaluate with pressure testing. If the test passes, then the cement job is deemed a success. Then there are logs. These attempt to tell us if we got the cement in the right place, and maybe something about the quality of the cement. However, even with the most sophisticated logs, we still cannot be sure we have hydraulic isolation in every well.

If only we could be sure we would do our job right. Maybe then we could have the confidence to change our casing designs and take advantage of the added support from the cement. If only we could be certain we did our job right. We would have more confidence that the seal we put in place would really last for the life of the well.

Did the cement set up in the right place at the right time? Are the cement properties what we need for the life of the well? Is there isolation in the wellbore that will last for the economic life of the well and beyond?

Designer slurries, sophisticated spacers, and advanced computer simulators are readily available. We still face the challenge of knowing the cement job actually went as designed and we got the results we wanted.

If only we knew.

Available from the SPE eLibrary: www.spe.org

SPE 88005 - “Use of Cement as Lost-Circulation Material—Field Case Studies,” by Fidan, E., SPE, Halliburton, et al.

SPE 90450 - “Characterizing Casing/Cement/Formation Interactions Under Stress Conditions: Impact on Long-Term Zonal Isolation,” by Mueller, D.T., SPE, BJ Services Co., et al.

SPE 94288 - “Should Horizontal Sections Be Cemented and How To Maximize Value,” by Ilseng, J.R., Dan A. Hughes Co., et al.
Subsea Oil/Water Separation: Main Drives and Challenges
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97375, "Application of Subsea Oil/Water Separation: Main Drives and Challenges," by M.W. de Figueiredo, Petrobras, prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June.

Petrobras is developing a subsea system for oil/water separation to minimize the effect that high water-production rates cause to the topside facilities when waterflooding an oil field. Most of the produced water can be separated at the seafloor and reinjected into the reservoir or into a water-bearing formation.

Introduction

During the exploitation-design phase of an oil field, activities focus on oil-production optimization. The oil-recovery mechanism is defined to maximize the recovery factor according to the reservoir and fluid characteristics. In most of the oil fields in Campos basin, waterflooding is used from the beginning of production. After water breakthrough occurs, the handling of produced water, which is a mixture of injected seawater and reservoir water, is of secondary importance during the design phase. Its priority increases only after water production increases. Conventionally, this water is separated from the oil and disposed of into the sea. This procedure takes place onboard the floating production units (FPUs) by use of very-large-volume vessels on a deck where space is critical, especially with the increasing plant capacity of recent units.

The use of a subsea system to separate most of the produced water at the seabed and send it somewhere other than the FPU plant is an attractive option. Such a system would allow the production plant to continue handling only a residual amount of water, eliminating new construction onboard to increase water-handling capacity. This system could enable adding extra oil-processing capability and, in many cases, increase oil production because of the lower wellhead backpressure that results from reduced water-lifting energy requirements.

Subsea separation presents challenging issues such as compactness and reliability. The full-length paper details this development, including the most promising scenario and the main benefits and challenges related to this scenario.
Benefits of All-Electric Subsea Production-Control Systems
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17106, "Benefits of All-Electric Subsea Production-Control Systems," by M. Theobald and C. Lindsey-Curran, BP plc, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May.

The oil and gas industry currently is using electrohydraulic subsea control systems as the standard to manage hydrocarbon production from subsea oil and gas fields. While these electrohydraulic controls will continue as the system of choice for the next 5 years, a desire to improve reliability and operational routines will increase the opportunity to use all-electric subsea production-control systems. The first offshore trial of an all-electric subsea production-control system and wellhead tree system was completed recently at the BP Magnus platform in the North Sea.

Introduction

To produce from greater water depths and harsher metocean conditions, the offshore industry has become technologically sophisticated. This applies both to the floating structures that support topside facilities in water depths greater than 200 m and the tieback technology to produce from long-distance remote step-out wells many tens of kilometers from the host facility.

In the early days of subsea tiebacks, each of the hydraulic valves needed to control the flow of hydrocarbons from the wellhead systems was controlled individually by a direct hydraulic connection back to the host facility and a topside control panel. The panel consisted of hydraulic pumps, motors, valves, and accumulators. This was a very successful and reliable concept because of its simplicity and relatively low cost. However, the limitation of direct hydraulics resulted in slow subsea-to-host actuator response times, and this limited tieback distance to approximately 15 km. In addition, the size and weight of the connecting umbilical hoses in all but the simplest of systems resulted in difficulties with transportation and installation. These limitations, together with the increasing requirements to collect reservoir-pressure and -temperature data, prompted the industry to develop more-sophisticated technology, including subsea control systems.
High-Quality Technologies as Pivots for Hydrocarbon-Reserves Expansion
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94915, "Key High-Quality Technologies as Pivots for Hydrocarbon-Reserves Expansion," by J.B. Navarro, SPE, Delta Are & Capillary Services Ltd., prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June.

Digital-technology trends transform hydrocarbon-production dynamics and could increase world oil reserves. Several inherent systems and techniques are commercially available, although the support of specialized hardware is required to complete truly integrated projects. This paper highlights high-resolution crosswell-seismic visualization, downhole-sensors systems, massive data-capture and -integrating systems, and other technologies supported with digital resources, such as intelligent drilling and completions, which increase productivity in many scenarios and reservoirs in Mexico and worldwide.

Introduction

Technology is nothing more than applying the human mind to the task of finding a new or better solution. Development and application of a wide array of sophisticated technologies will be the hallmarks of successful companies in the future.

Within intelligent drilling and completions, the industry uses multidisciplinary technology including 3D and 4D seismic, highly propped hydraulic fracturing, tubingless well designs, multiple completions, high-resolution logging tools, numerical reservoir simulation, expert systems, and optimized multiple perforating systems for hard formations.

In Mexico’s northern-region wells, tubingless completions, integrated with advanced stimulation practices and reservoir analysis, improve production results from low-permeability formations. However, stimulation procedures depend on the well-completion method used.

Combining the use of propellants with perforating improved early production of the treated wells as well as propped-fracture treatments did. The concept of combining the propellant on a sleeve with the perforating gun is unique, and this technology shows promise of solving many inherent perforating problems.
Value of Information for a 4D-Seismic Acquisition Project
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94918, "Value of Information for a 4D-Seismic Acquisition Project," by P.R. Ballin, SPE, G.S. Ward, C.V. Whorlow, and T. Khan, BP Trinidad and Tobago LLC, prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June.

Decisions regarding data acquisition should involve a cost/benefit analysis. While cost identification usually is easy, determining the value gained from new data is especially difficult when the benefits are mostly indirect. This is the case with 4D-seismic projects in which the main contribution is to reservoir and production management. This work describes the decision-tree process used in the life of complex seismic (LOCS) value-of-information study.

Introduction

In 2004, BP Trinidad and Tobago faced the challenge of valuing several seismic-survey options over the Greater Cassia Complex in the Columbus basin, Trinidad. The complex contains large gas reserves in five currently producing fields, several new field developments, and future exploration potential. Development of these reserves is complicated, having 27 stacked reservoirs with reserves trapped in more than 100 separate compartments. With an aggressive well program planned, the team had to identify and value the style of survey required to accomplish the following.

- Improve the static seismic image over the southern half of the complex, which is affected by shallow-gas imaging problems.

- Value the dynamic benefits that 4D seismic could offer for reservoir management and future well placement.
Seismic-While-Drilling Using a Swept-Impulse Source
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 92114, "Seismic-While-Drilling Using a Swept-Impulse Source," by J.J. Kolle, SPE, and K. Theimer, Tempress, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.

This paper describes a prototype swept-impulse hydraulic tool capable of generating a broadband seismic signal at the bit while drilling. The source was designed to overcome the limitations of drill-bit seismic services by allowing operations with polycrystalline-diamond-compact (PDC) bits in inclined wells and in soft formations. The swept-impulse seismic source generated a broadband, high-intensity compressional-wave (P-wave) signal that can be used for high-resolution seismic profiling and look-ahead imaging while drilling.

Introduction

Seismic-while-drilling (SWD) services provide operators with real-time depth correction of seismic records to improve drilling accuracy and placement of liners. Pore-pressure prediction ahead of the bit would provide substantial benefits as a result of the reduced risk of blowouts. Between 1960 and 1996, there were more than 30 blowouts per year in Texas, Louisiana, and the U.S. Gulf of Mexico.

Seismic services offer the best approach to characterize formation pressures because of the substantial effect of pore pressure on seismic velocity. When integrated with other information (such as surface seismic, offset-well velocity profiles, and drilling parameters), it may be possible to predict pore-pressure levels at the bit and ahead of the bit. Through the Deepstar consortium, operators have developed the following criteria for pore-pressure-prediction services.

- No delay of conventional drilling operations.

- Prediction range of 1,000 ft ahead of the bit.

- Accuracy better than 50 ft.

- Provide formation velocities within 5% of a conventional wireline vertical-seismic profile (VSP) service.

- Real-time prediction—defined as less than 10 hours.

The service industry has developed a range of seismic techniques for seismic profiling and pore-pressure prediction. Existing practices include predrill seismic interpretation, wireline VSP, drillstring VSP, and drill-bit SWD.

Predrill seismic surveys can provide an indication of velocity anomalies. The value of seismic surveys is limited by the large depth uncertainty, particularly in exploration areas.

Wireline VSPs have been used to provide check-shot surveys using air-gun sources. On deepwater offshore rigs, the rig-time costs are high, and failure of the wireline may disable the blowout preventer, causing a loss of well control.

Drillstring VSP is a relatively new service that is similar to wireline VSP except that the receivers are on the bottomhole assembly. An air-gun array is deployed from the rig and fired multiple times while a connection is being made. Data from receivers are stored in a memory tool downhole for processing after the bit run.
Reply to Discussion of "Beyond Beta Factors: A Complete Model for Darcy, Forchheimer, and Trans-Forchheimer Flow in Porous Media"
Authors: Barree R.D. , Conway M.W.
Published: February 2015

The authors of SPE 893251 would like to thank FracTech and Halliburton ERC for their discussion of the paper. The data presented in their discussion provide excellent examples of what drove Stim-Lab to investigate non-Darcy flow in more depth and to arrive at the conclusions presented in paper SPE 89325.

Although the data in the FracTech and ERC examples appear to fall on a straight line on the Forchheimer graph, the intercept value of permeability does not represent consistently accepted values of permeability for those proppants. For years, Stim-Lab had observed apparently linear Forchheimer graphs with an intercept value that failed to agree with the directly measured Darcy (low-rate) permeability. In this discussion we use ki as the apparent Darcy permeability from the intercept of the Forchheimer equation and kd as the directly measured Darcy absolute permeability at low rate. For Forchheimer’s equation to be valid, both slope and intercept, ki and β, must be equally valid. That is ki must equal kd and the straight line of slope β must intercept at ki = kd.

The FracTech data in Fig. D-1, representing test results for 20/40-mesh white sand at 1,000-psi stress, was digitized, and the apparent permeability at each point was computed from the inverse permeability. The data were plotted here in Fig. R-1 on the log-log inertial graph as the magenta diamonds. The coefficients from the FracTech linear regression of their Forchheimer graph were used to calculate kapp over a range of values of ρv/µ. The results are shown in Fig. R-1 as the solid blue line. Note that the FracTech data fall on a slope that is much shallower than −1.0, as indicated by the solid black line. The Forchheimer fit of their data yields an apparent value of Τ=34.86, kd=91.1 darcies, and does not approach a unit slope until ρv/µ approaches 1,000.

The red line on the graph is based on data from the Stim-Lab database and Predict-K. The database contains data sets for six 20/40-mesh sand proppants with 28 measurements of permeability at approximately 1,000 psi net stress. The average directly measured Darcy permeability for these 28 tests is 288 darcies, with no test showing less than 202 darcies. This curve fits the FracTech data better than their own regression, honors the actual Darcy permeability for this proppant, and yields values of β and Τ consistent with the mean particle diameter of the sample. In comparison, the reported Darcy permeability value from the FracTech data fails to correlate with any published or estimated Darcy permeability values for 20/40-mesh proppant at this stress. The separation between the red and blue lines in the figure shows the error in permeability generated by the flawed Forchheimer analysis.