bluuebunny/crossref_metadata_2025 huggingface dataset:
Swelling Elastomers Improve Well and Reservoir Management in Horizontal Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 107882, "Improved Well and Reservoir Management in Horizontal Wells Using Swelling Elastomers," by Majid Abdullah Mahrooqi, SPE, Ghaliba Hinai, and Franz Marketz, SPE, Petroleum Development Oman, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, Califoronia, 11–14 November. The paper has not been peer reviewed.

To increase recovery from maturing reservoirs, Petroleum Development Oman (PDO) is developing the capability to detect and shut off unwanted water and gas. Swelling elastomers (SEs) have been deployed to segment horizontal wells in combination with surveillance and shut-off technologies. In beam-pump wells, dual wellheads have enabled logging while pumping.

Introduction

The South-field fields in southern Oman mostly are mature oil fields operated by PDO. The fields produce medium-gravity viscous crude with viscosity ranging from 200 to 550 cp. The fields have been producing since the mid-1980s. Initial field development was by vertical wells. Since the mid-1990s, development has been primarily with horizontal wells. Production is from a combination of eolian and glacial sediments. Reservoir heterogeneity is high.

Almost all South field wells must have sand control. The horizontal reservoir section is appproximately 350 to 500 m long and may cross both reservoirs. The horizontal section is drilled with a 6 1/8-in. drill bit and completed with a standalone 4 1/2-in. sand-control liner using 200-μm wire-wrap screens (WWSs) in open hole. This results in an open annulus between the sand-control liner and the formation. More than 90% of the wells are artificially lifted by use of beam pumps, hindering accessibility because of surface units and rods.

Since the start of infill drilling, the new oil production has been dominated historically by high initial water levels, and as of 2002, new wells produced an average of 3 bbl of water for every 1 bbl of oil during their first year of production.

SEs

SEs have been available for a number of years, and recently the oil industry has become more interested in them. Some SEs are water based and some are oil based. Because of the high water production from startup in the South field, water-based SEs were selected. The theory is that specially designed rubber elements will swell, when contacting formation water, to seal off the annulus between the completion and the wellbore.

A key element to achieve improved oil recovery through well and reservoir management in a horizontal well is segmenting the well into different flow units. SEs are being deployed to enable segmentation. The SE tool provides zonal isolation through the swelling of the elastomers when contacting produced water in the wellbore. Fig. 1 shows a casing joint with SE seals.
Fluid-Movement Measurements Through Eccentric Annuli Produce Unique Results
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 109563, "Fluid-Movement Measurements Through Eccentric Annuli: Unique Results Uncovered," by Larry Moran, SPE, ConocoPhillips Co., and Mark Savery, SPE, Halliburton, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. The paper has not been peer reviewed.

Better understanding of fluid movement through eccentric annuli over a wide range of casing standoffs and flow rates is essential for proper cement placement. A full suite of physical testing was performed to find differences in velocities and flow rates on the wide side vs. the narrow side of an annulus. Nine models were built, each taller than 6.5 ft and each with unique annular geometries. The annular sizes chosen are common to primary-cementing operations. The flow area was divided at the top of each model to capture wide- and narrow-side flow variations. The weight of recovered fluid vs. time was recorded and used to determine flow rates and velocities on both sides.

Introduction

In oil- and gas-well completions, cementing operations are used to ensure zonal isolation. On many production liners, the wellbore geometry is such that very slow flow rates during cementing are required to prevent fracturing/losses. In addition, liner-top packers and tiebacks give annular clearances that are quite small. These narrow clearances cause excessive backpressure with normal flow rates, often requiring the use of slow-flow-rate cementing to prevent losses. The other option is pumping cement at a high rate with losses, often with uneconomical and undesired outcome.

The most likely causes of slow-flow-rate cementing failure were poor centralization and poor compatibility between muds, spacers, and cements. Poor centralization causes channeling, and poor compatibility causes viscous interfaces leading to channeling. Today, centralizers are better than in the past and higher degrees of centralization are often attempted. Spacers also are better today. Another significant change is cement slurries that are often much thicker than anything pumped years ago. Accurate modeling of these flow phenomena can help uncover the conditions required to achieve a good cement bond around the entire casing string.

Experimental

The goal was to build a set of large-scale apparati that allowed a complete study of steady-state-flow response of various fluids in eccentric annuli. Nine pipe-in-pipe eccentric annular models were built using standard casing materials. Each model was unique in its combination of geometry and inner-pipe standoff.
Deepwater Completions Offer Great Potential
Authors: Probert Tim
Published: February 2015

Guest editorial

Deepwater E&P is a growing part of the world's energy supply. Estimates are that deepwater production will grow 78% by 2011, making it one of the leading growth sectors in our industry.

The explanation is simple: many of the world's largest untapped reservoirs are in deep water. The "golden triangle" of the Gulf of Mexico, offshore Brazil, and west Africa are joined by newer areas of opportunity in India, Malaysia, Australia, the eastern Mediterranean, offshore Norway, and eastern Canada. There are even more promising possibilities in the salt and subsalt reservoirs located in the basins of the golden triangle.

The industry's definition of deepwater exploration and its technical challenges are expanding along with knowledge of the reserves. Ten years ago, deep water was anything more than 1,500 ft water depth. Today, the deepwater frontier is more than 5,000 ft. The frontier of a decade ago is now practically routine. And along with these greater water depths, operators are facing increasing total well depths and higher temperatures and pressures.

The deepwater opportunity comes at a price—the high rig rates and capital intensity make it a high-risk and high-reward proposition. And the enormous technical challenges make deepwater wells a focal point for developing and deploying advanced technology in every aspect of well construction and production.

Completions technology brings operators more production, lower costs and lower risks, and holds the promise of enabling the future production the world demands. What follows is a snapshot of the deepwater completions picture, with emphasis on those areas that will contribute most to operators’ success. All these elements are interrelated and complementary. Developments in one area contribute to the effectiveness of the others. Ultimately, it is the integrated development of all aspects of deepwater completions that promises to make possible the production the world is counting on over the next several years.

High-Rate Fracturing Systems

Stimulating production through hydraulic fracturing is a proven way of making deepwater wells economical. Frac packs of long, thick unconsolidated producing intervals in turn depend on the ability to pump frac fluid at a high rate and place proppant in large quantities.

Tools and techniques that make access to these zones profitable include using hydrostatic properties of frac fluids to increase bottomhole fracture pressure without unsafe surface treating pressures. This helps achieve the high pressure needed for the fracture without exceeding the pressure rating of surface equipment. Also, tool systems using carbide-protected crossover tool designs are now able to withstand the large volumes of proppant at high rates needed to capitalize on the high-rate fluid pumping. These technologies are valuable in their own right, and they are crucial to the development of single-trip multizone completions.
Trends and Strategies in Recruiting and Retaining Talent
Authors: Hamilton John
Published: February 2015

Talent & Technology

The upstream oil and gas industry faces unique issues and challenges in today's changing global economy. Despite the recent downturn, multinational companies still will need to augment staff and expand the technology used in critical areas of the world to meet the growing needs of energy hungry countries. These companies face a number of challenges in meeting the human capital demands needed to meet the heightened demand throughout the world.

These unique challenges include attracting highly skilled employees to sometimes remote locations with extreme weather conditions and retaining these employees as competing companies seek to relocate top talent to new regions requiring similar skills. In addition, the shifting workforce will create additional strains in meeting staffing requirements. As other sectors have seen, senior level workforce personnel in the baby boomer generation are beginning to retire and vacate high-level positions that require experience and specific expertise. This workforce adjustment will mandate that younger employees quickly learn skills and gain the necessary experience to maintain production quality as highly experienced employees retire.

Trends in Recruitment

Companies that will need to attract and recruit employees in the future will need to implement new strategies and tactics to address the immediate as well as long-term needs of reaching a targeted group of prospective employees. For instance, today's workforce is looking for more than a just a job. Younger job candidates are much more interested in creating solutions to daily challenges, working with new science and technology, and in seeking career growth and development. These individuals choose a career path on the forefront of innovation and find immense job satisfaction being a part of this. Therefore, employers must also "sell" the position to a prospective hire during the recruitment and interview process.

Companies must start by looking internally to identify what makes a successful employee. An understanding of the motivation for the best workers will help to create a picture for what to look for when hiring. This will include what attracted this employee to the company, what makes him/her successful in the organization, as well as the factors that cause this person to stay with the company. Applying this information to the company's business model of retaining and strengthening the current workforce will create a solid foundation.
Technology Focus: Intelligent Fields Technology (May 2009)
Authors: Alves Iberê
Published: February 2015

Technology Focus

Intelligent fields, e-fields, i-completions, and digital fields are terminologies used to describe the use of real-time data to obtain the greatest results from wells, reservoirs, or fields. This achievement can be reached through transforming raw data into a most precious resource called "useful information." The analysis and use of the information in an effective control system leads to the desired optimization of a petroleum production system. This process is analogous to transforming a potential raw mineral into a precious jewel.

Many industries take increasing advantage of the digital era. Advances in hardware, software, and communications technology are used to improve performance. More specifically, the petroleum industry has proved that these paradigm shifts do pay off. In facing the challenge, it has been possible to meet the continuously growing demand for energy. Also, such challenges have led to successful operations in adverse conditions and locations throughout the world.

An adequate mindset to embrace this new technology from an operator's perspective will be decisive. To apply it successfully, companies must master the intricacies associated with the deployment of this new technology.

The concept of intelligent fields reveals a promising scenario for the future of the industry. The driving force is the potential for enhanced production, reduced operation expense, and improved safety. Nevertheless, these goals may be jeopardized, not because of unavailable technologies, but due to a lack of participation or integration of the various disciplinary teams.

The ultimate intelligent-field management will be achieved when we are capable of acquiring real-time data from an entire set of reservoirs, our main asset, completely closing the production automation cycle. Some intrinsic difficulties are bound to occur, although modest advances have been achieved in reservoir-data acquisition.
From Real-Time Data to Updated Models: Challenge of Intelligent Fields Applied to Gas Storage
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 113171, "From Real-Time Data to Updated Models: The Challenge of Intelligent Fields Applied to Gas-Storage Business," by A. Tiani, SPE, G. Bartolotto, P.D. Strippoli, and R. Latronico, Eni E&P, and G. Spitaleri, Stogit, prepared for the 2008 SPE Europec/EAGE Annual Conference and Exhibition, Rome, 9-12 June. The paper has not been peer reviewed.

Underground gas storage (UGS) is a complex activity, which faces the challenge of combining variability of daily commercial-client requests with the reservoirs’ capability to deliver. Stogit has implemented an integrated system that dynamically links databases, visualization tools, and reservoir/well simulators to assist the management process. The challenge has been to extract the maximum information from the available database and to computerize the process of updating well/reservoir performance.

Introduction

The intelligent-field concept is a promising scenario for the future of the oil and gas industry. The increasing amount of available data, use of real-time subsurface sensors, and the trust in the potential of the digital revolution are the main drivers. However, the kind of automation required is peculiar to the oil industry because the detailed characteristics of the reservoir are unknown. The intrinsic impossibility to measure directly, to "see," the reservoir requires continuous interpretation of indirect data to feed complex models.

Going from data to models to decisions is the concretization of value of the whole petroleum-engineering activity. Decisions are enhanced by a value chain that is able to define a limited number of clear scenarios from the data. Whereas downstream oil and gas processes have a degree of certainty and automation comparable with other industries, it is a big challenge to automate the subsurface process. In this context, the measure/analyze/decide cycle, as the basis of each feedback loop, encounters processes in which the human factor is mandatory and the work and experience of the petroleum specialist are required. Field surveillance and optimization of the production/storage cycle require fast and effective decision making, supporting the daily-to-hourly market changes.

Performance Surveillance for Gas-Storage Fields

To monitor well production and performance and to control the production from the wells remotely, many sensors and controls have been deployed to manage the operativity of the wells and fields from a central operations-control room. The main data acquired are pressure and temperature at the wellhead, at cluster nodes, and at the plant manifold; gas rate at the wellhead, cluster nodes, and plant manifold; production of liquids (e.g., water and gas); and status of valves, compression units, treatment facilities, lines, separators, and others.
Toward the E-Field: Continuous Monitoring of Pore-Fluid Phase Using Horizontal Wells
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119681, "Toward the E-Field: Continuous Monitoring of Pore-Fluid Phase Using Horizontal Wells," by B.J. Evans, SPE, and B. Hartley, Curtin University, Australia, and N. Keshavarz, Research Institute for the Petroleum Industries, Iran, prepared for the 2009 SPE Middle East Oil & Gas Show and Conference, Bahrain, 15-18 March. The paper has not been peer reviewed.

The electric field, or e-field, is a method of monitoring oilfield production remotely and continuously over a long term by use of vertical and horizontal wells. Continuously monitoring fluid movement requires monitoring with horizontal wells. It has been shown that seismic methods can show subtle changes in the pore-fluid phase, which enhances the potential for long-term monitoring where pore-pressure is declining, under waterflood or CO2 flood, and in areas in which gas is being replaced by water.

Introduction

As the production of oil and gas depletes reserves, it is important to determine the location of missed pay zones. When 3D surveys are repeated over time, after subtraction from the original 3D data, the difference is known as the repeat-3D-difference volume or the time-lapse (or 4D) image volume. These data can show missed pay zones, and, provided that seismic-reflection-data quality is high (with signal/noise ratios of approximately 12:1), it becomes possible to determine changes in oil and gas location and, on the basis of pressure effects that improve production management, enable drilling of step-out production wells.

Such 4D-difference slices through the reservoir provide knowledge of oil in place, the location of high gas saturation, pressure, and information on the areal extent of thief zones. This method requires a high signal/noise ratio to make the resulting difference image trustworthy for dependable drilling decisions. Such high signal/noise ratios are very rare and tend to apply to offshore surveys in which very calm sea conditions allow high-level signal/noise ratios.

The problem with land surveying is that the source is in contact with the soil surface and, typically, produces high-level coherent noise, both compression and shear energy, as well as having all of the attendant issues of strong absorption and scattering. Near-surface layering of complex geological formations such as basalt flows, sand dunes, hard pavements, river courses, and mountains along with variable weather conditions from one 3D survey to the next all contribute to the inability of the source to radiate a consistent amount of energy or consistent enough radiation pattern from one survey to the next. Different receiver couplings result in a poor signal/noise ratio and an inability to provide a high-quality 4D-difference image.
Technology Focus: Multilateral/Extended Reach (May 2009)
Authors: Negrao Alvaro
Published: February 2015

Technology Focus

Our industry has overcome many difficulties during recent years. Successes have been achieved with drilling projects in sensitive environments, remote-access areas, and high-technological-demand projects. New technologies have been developed at a fast pace to fill the needs.

Technologies that achieve better recovery with a simultaneous reduction in capital expenditure are preferred. The use of extended-reach and multilateral wells aligned with good drilling performance will reduce capital expenditures. Although the profiles of those wells become more complex, with long horizontal sections or multiple legs, better performance is possible through deployment of an integrated project team that appropriately addresses the drilling and completion challenges during the planning phase. Subjects such as wellbore stability, well cleanliness, multilateral junctions, appropriate sand control, openhole completions, inflow-control completions, and inflow-performance relationship must be analyzed carefully during the well-design phase.

The project-team assessment during the execution phase must include the latest techniques in seismic interpretation, deployment of real-time logging tools to deal with reservoir heterogeneity, and real-time update of the Earth model. Real-time data are essential for management of equivalent circulating density because of the narrow margin between pore pressure and fracture gradient.

The well-planning process must be complemented by an improvement in operational performance. New approaches with good quality control must be implemented urgently to reduce the nonproductive time (NPT) while drilling wells. Our industry faces performance problems with wells reaching an NPT index of more than 40% in the Gulf of Mexico. The responsibility for such a high NPT index can be shared equally by drilling contractors, service companies, and opera-tors. Today, NPT in offshore wells can reach an annual cost of approximately USD 70−90 million per rig, and this will be reduced only with improvement in maintenance, better engineering practice, and qualified personnel. Integrating the drilling engineers into the project team early, use of the latest technology, and focusing on operational excellence are essential for the industry success.

Multilateral/Extended Reach additional reading available at the SPE eLibrary: www.spe.org

SPE 115099 • "Technical, Economic, and Risk Analysis for a Multilateral Well" by D. Arcos, Texas A&M University, et al.

SPE 119506 • "How Continuous Improvement Led to the Longest Horizontal Well in the World" by Kumud Sonowal, Maersk Oil Qatar, et al.

SPE 116138 • "Multilaterals Drilling and Sustainable Openhole Production From Theory to Field Case Studies" by Son K. Hoang, University of Oklahoma, et al.

SPE 115742 • "Advanced Wells: How To Make a Choice Between Passive and Active Inflow-Control Completions" by V.M. Birchenko, Heriot Watt University, et al.
Casing Ultradeep, Ultralong Salt Sections in Deep Water
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 114273, "Casing Ultradeep, Ultralong Salt Sections in Deep Water: A Case Study for Failure Diagnosis and Risk Mitigation in Record-Depth Well," by Jincai Zhang, SPE, Shell Oil Company; William Standifird, SPE, Knowledge Systems; and Chris Lenamond, SPE, Nexen Petroleum U.S.A., originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed.

The deepest well drilled to date in the Gulf of Mexico (GOM), the Well 1 discovery well in Green Canyon, required setting casing in a 15,000-ft-thick section of tectonically active salt. After casing collapsed in the initial wellbore, a comprehensive model was developed to characterize wellbore stability, the salt-creep mechanism and its implications for well design, and mitigation options for future well construction.

Introduction

Subsalt and near-salt formations are among the most attractive exploration prospects in many operating areas including the GOM, offshore West Africa, Brazil, the southern North Sea, Egypt, and the Middle East. One of the characteristic features of the northern GOM salt trend is that the salt bodies are highly mobile. High mobility has two significant implications for wells drilled through salt:

"creeping" salt masses can exert catastrophic stresses on casing, and

in areas near the salt/rock interface, salt movement can create unstable rubble zones that can make drilling difficult or impossible.

One of the key challenges for well construction in subsalt environments is maintaining casing integrity. Salt-induced casing collapse has occurred in a number of GOM wells, including Well 1. Well 1 was drilled in 2005 and, at the time of construction, was the deepest well in the GOM. The well was drilled through a salt body more than 15,000 ft thick and eventually reached a total depth of more than 28,000 ft true vertical depth. The casing collapsed near the base of the salt nearly 3 months after the salt section was cased. The wellbore was abandoned and was sidetracked successfully to reach 34,189 ft.

The objective of this study was to characterize the salt-creep mechanism and its implications for casing failure in Well 1 and to develop options for well design to avoid future failure events. Well 1 experienced drilling-fluid losses and hole ballooning in the subsalt formations. Given the extreme depths, fluid losses and hole ballooning could jeopardize the feasibility of future projects in the area.

Analysis of the geomechanical environment reveals many challenges; northern-GOM salt bodies are among the most varied and complex in the world. Some are active; some are passive. On a local geologic scale, the dynamics of salt creep are dependent on such factors as temperature, salt mineralogy, and overburden.
Trapped-Annular-Pressure Mitigation: Spacer Fluid That Shrinks - Update
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112872, "Trapped Annular Pressure Mitigation: A Spacer Fluid That Shrinks - Update," by B. Bloys, SPE, M. Gonzalez, SPE, J. Lofton, R. Carpenter, SPE, S. Azar, SPE, D. Williams, J. McKenzie, SPE, and J. Capo, SPE, Chevron; R. Hermes, Los Alamos National Laboratory; R. Bland, SPE, R. Foley, SPE, and F. Harvey, SPE, Baker Hughes; J. Daniel, F. Billings, and I. Robinson, Lucite International; and M. Allison, Flow Process Technologies, originally prepared for the 2008 SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.

In subsea-completed wells, fluids commonly are trapped in casing annuli above the top of cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced fluids, thermal expansion can create very high pressures and cause the collapse of casing and tubing strings. A successful field trial has been conducted in a 9,800-ft-deep gas well of a water-based spacer fluid that upon heat-triggered polymerization shrinks 20%, mitigating trapped annular pressure (TAP).

Introduction

TAP, also called annular-pressure buildup, is caused by the thermal expansion of fluids trapped in casing annuli between the top of cement and the wellhead. The pressure buildup usually is a result of heat transfer from produced fluids or from hot drilling fluids circulated while drilling a high-pressure/high-temperature well The pressure can exceed the collapse strength of the casing and production tubing. In land wells, the pressure is relieved easily by bleeding off some fluid through a casinghead valve. In subsea-completed wells, wellheads are much less accessible and generally not fitted with the necessary valves.

Perhaps the most successful mitigation approach has been the use of vacuum-insulated tubing (VIT). This technique generally has been successful in keeping the annular-fluid temperatures within an acceptable range. However, with the advent of deeper and hotter wells in deep water, the limits of the protection provided by VIT are being approached in two ways. First, deeper wells have much higher hanging weights that are reaching the stress limits of VIT designs. Second, the greater depths also are producing higher temperatures. Even with the insulating effects of VIT, the temperatures are sufficiently high that pressures are predicted to increase to unacceptable levels.

A new approach created a water-based spacer fluid to be used just ahead of the cement. The spacer contains 10 to 30% emulsified liquid methyl methacrylate (MMA) monomer. The liquid MMA shrinks 20 vol% upon polymerizing. The polymerization is triggered by heat and an appropriate chemical initiator. MMA is emulsified into a simple water-based fluid that is intended to be the last spacer pumped just ahead of cement, filling most of the open annulus. The monomer has a low flash point similar to methanol, and it must be handled carefully but has a long record of safe industrial use.
Comments (June 2004)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Study Substantiates Merits of Rotary Steerable Over Directional Drilling Systems
Authors: JPT staff _
Published: February 2015

This article contains highlights of paper SPE 84449, "Development of the Industry's First Slimhole Point-the-Bit Rotary Steerable System," by D. Stroud, M. Russell, and S. Peach, Precision Drilling (U.K.) Ltd., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
A JPT Roundtable: The Funding and Uptake of New Upstream Technology
Authors: Daneshy Ali
Published: February 2015

JPT Roundtable - No abstract available.
IT Security for Oil and Gas Companies
Authors: Cole Richard , Thomas Bret
Published: February 2015

Management - No abstract available.
Overview: Deepwater E&P (June 2004)
Authors: Tollefsen Svein
Published: February 2015

Overview - No abstract available.
Commercial Development of Hub Platforms and the Value to E&P Producers
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15108, "The Commercial Development of Hub Platforms and the Value to E&P Producers," by Bart Heijermans and Drew Cozby, El Paso Energy Partners L.P., prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
Ultradeepwater Gravity-Based Separators
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15175, "Innovative Technology for Ultradeepwater Gravity-Based Separators," by Jarle Michaelsen, ABB Offshore Systems Inc., prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
Appraisal and Development Plan for the Heavy-Oil Jubarte Field
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 16301, "The Appraisal and Development Plan for the Heavy-Oil Jubarte Field, Deepwater Campos Basin, Brazil," by Marcio F.C. Bezerra, Carlos Pedroso Jr., Antonio C.C. Pinto, SPE, and Carlos H.L. Bruhn, Petrobras, prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
Technology's Value in the Upstream Oil and Gas Industry
Authors: Daneshy Ali , Bates Tom
Published: February 2015

The petroleum industry has long grappled with the assessment of the value of technology and its role in corporate strategies. Over the past 2 decades, the questions posed by who pays for, who owns, and who benefits from technology have created an increasingly fractured view of new product development. This has created a paradoxical environment in which E&P technology funding is declining at a time when the incentive for developing new technology has never been greater.

The value of E&P technology is well documented. In the 1990s, three significant new technologies changed the landscape of the industry. Multiple streamers deployed in the acquisition of 3D seismic dramatically reduced the cost of high-quality data. The creation of multiclient libraries made it possible for smaller independent operators to play in the same league with supermajors in geographic domains such as the Gulf of Mexico. Horizontal drilling, including logging-while-drilling and geosteering tools, made it possible to drill “designer” wells in complicated offshore environments and substantially increase the rate of recovery in ordinary reservoirs. Finally, subsea and deepwater technologies allowed the industry to access reserves in unprecedented water depths. Coupled with seismic and drilling advances, deepwater offshore fields were placed in production at costs lower than anyone could have imagined a decade earlier. One supermajor reported that real finding and development costs and operating expenses per barrel dropped by more than 50% from 1985 to 1995. It is not surprising then to note that annual worldwide oil discoveries nearly doubled from the early 1990s to the late 1990s as these new technologies became fully deployed.

This perspective provides an insight into the enormous value that technology can create for the oil and gas industry. Even a small incremental reduction in the cost of each barrel of produced oil generates enormous savings when one considers that globally the industry produces in excess of 100 million BOE/D. Unfortunately, the oil price collapse of 1998–99 destroyed much of this technology momentum. New technologies have not replaced the value created by 3D seismic, horizontal drilling, and deepwater products. As a result, discoveries are lower (Fig. 1) and costs are higher today than 10 years ago.

Owner Reaps the Benefits

In many other industries, such as computers, pharmaceuticals, and electronics, technology is directly responsible for generation of value. The developers, owners, and financial beneficiaries are the same. However, because the E&P industry is very different from consumer-focused industries, a dramatically different picture emerges. With the majority of potential value creation in the reservoir, the owner of the reservoir typically gains much larger benefits than the owner of the technology. As long as technology is available and accessible, the owner of the reservoir can reap its benefits with-out having to directly participate in its development. This is the conundrum that we seek to resolve.
Cost-Effective Methane Emissions Reductions for Small and Midsize Natural Gas Producers
Authors: Fernandez Roger , Petrusak Robin , Robinson Donald , Zavadil Duane
Published: February 2015

Introduction

U.S. demand for natural gas continues to grow dramatically, in large part because methane is the cleanest-burning fossil fuel. Onshore and offshore drilling and production continue to expand, often in very challenging plays ranging from shallow low-pressure coalbed methane to deep high-pressure/high-temperature gas production. A significant amount of this demand is expected to be met by independent producers.

The U.S. Dept. of Energy estimates that small and midsize independent operators produce more than two-thirds of the natural gas in the lower 48 states. Independent producers drill 85% of new gas wells in the U.S., and 80% of these companies have fewer than 20 employees. Methane emissions from the U.S. natural gas production sector are approximately 150 Bcf/yr. With record sales prices for natural gas and high consumer demand, natural gas producers have great incentive and opportunity to reduce currently lost product and increase their revenue. Often many small producers lack the time and technical staff to research and evaluate cost-effective methane emission reduction opportunities, yet there are numerous proven and cost-effective methane emissions reduction technologies and techniques that are available today to the small to midsize producer.

While individual releases of methane may appear to be minor, emissions are often continuous in nature, and cumulatively they become economically significant. This article provides information on methane emission reduction options that were developed by operators and promoted by the U.S. Natural Gas STAR Program, and are economic for small and midsize producers. In addition to increased revenue through reduced methane loss, many of the technologies and practices outlined here reduce operating costs, increase overall production, and provide high rates of return. All of these technologies and practices have been reported by gas producers through their participation in the Natural Gas STAR Program. This paper provides information and tools to help independent producers determine the most profitable gas emissions savings options for their operations.

We describe 25 cost-effective methane emission reduction technologies and practices in Table 1, provide costs and savings data in Table 2, and crosswalk technologies and practices with production characteristics in Table 3 to help determine where each methane savings option is most likely to work. Finally, we provide a method to scale this data to your operation and calculate your potential economics in Fig. 1.
High-Stakes National and International Litigation: Management Issues
Authors: Welsh Ron , O'Gorman Kevin
Published: February 2015

An employee has just sued an oil and gas company for U.S. $1 billion on behalf of himself and countless unnamed people who have nearly identical claims. What does company management do?

From equipment accidents to plant and pipeline explosions to gas releases and chemical spills, oil and gas executives regularly face risks that would terrify executives in other fields. The resulting lawsuits often mushroom into myriad class-action law-suits with plaintiffs clamoring for enormous damage recoveries. At the same time, “lesser” lawsuits in all shapes and forms abound, including litigation ranging from sexual harassment to royalty claims.

Because of the oil industry’s sweeping size, scope, and complexity, the industry is not just fertile ground for legal action—it is a veritable petri dish. In the post-Sarbanes-Oxley world, more and more oil companies have come to believe that legal matters are just as much management business as legal business. The more that management knows about the broad issues of lawsuits, the more prepared it will be to know how to direct its lawyers and guide its case to a successful conclusion.

Class-Action Lawsuits

Because class-action lawsuits are potentially the most costly of all litigation that oil companies may face, it is helpful to know the basics. First, class-action suits can make cases involving large numbers of people more manageable for both sides: plaintiffs and defendants. For example, when scores of people claim to have suffered similar harms, it is impractical to bring each of these claims to trial individually. If a court agrees, a class-action lawsuit may proceed in the name of one or only a few individuals representing all similar claimants. Ultimately, all the unnamed claimants are governed by the issues determined to be common to the group.

At the outset of class actions, management and its attorneys should make a pivotal decision—Does the company embrace the idea of a class action or not? Surprisingly, the answer is not always “no.” Occasionally, management may tolerate, if not welcome, a class action for sound management reasons. For instance, when any large business such as an oil company has a potential exposure, it should objectively analyze that exposure in terms of the size of the claim, the strength of its defense, and the cost to defend or settle later. As an example, one lawsuit for U.S. $1,500 scarcely qualifies as a significant exposure to any large company. But 10,000 carbon copies of that lawsuit can make just the attorneys’ time to manage and defend each one ruinous. Consider the number of formerly vibrant companies that ended up in bankruptcy as a result of thousands of asbestos claims.

That is why, as odd as it sounds, the chant “Turn it into a class action” may occasionally be the company’s mantra as much as it is the claimant’s. As a result, the question is usually better asked as, “Forget the claimants; does a class action give the company a way to put a widespread exposure behind us at a wholesale cost rather than at 10,000 retail costs?”
Overview: Deepwater Exploration and Production (June 2005)
Authors: Barnes John E.
Published: February 2015

In recent years, the industry has met some amazing deepwater technology challenges. Drilling and production in water depths that just a few years ago would have seemed impossible now are considered routine. Not long ago, a site in water depths greater than 150 m was considered deep, and the Cognac Project—at more than 300 m—was considered a remarkable feat of technology.

Today, the feasibility of a project in 2000-m water depth is not an issue. Instead, project efforts focus on topics such as design robustness, effective project-execution strategies, reliability of operations, and cost-effectiveness. It is a tribute to technical innovation that, for most deepwater projects in less than 2000 m of water, several different acceptable methods often are available to solve specific technical challenges.

Operators, designers, constructors, and installers continue to improve deepwater technologies and reduce cost and schedule risks. Areas such as well testing, reservoir evaluation with minimal data, riser systems, and flow assurance are being addressed to improve project execution and delivery. Meanwhile, new projects are benefiting from the application of lessons learned from previous efforts.

Recent work has achieved promising results in special projects for which water depths reach 3000 m. Today’s challenge is to make the issues at that depth as commonplace as those in less that 2000 m. From a historical perspective, it is truly startling that work on these challenges is proceeding in an almost routine manner, with complete confidence that viable solutions will be found.

Additional Deepwater Exploration and Production Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 92616 Mooring and Riser Management in Ultradeep Water and Beyond

SPE 91012 Incorporating Uncertainties in Well-Count Optimization With Experimental Design for the Deepwater Agbami Field

Available at the OTC Library: www.otcnet.org

OTC 17292 Holstein Truss Spar and Top Tensioned Riser System: Design Challenges and Innovations

OTC 17683 Lessons Learned From the Evolution and Development of Multiple-Line Hybrid Riser Towers for Deepwater Production Applications
Barracuda and Caratinga Development Project
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17052, "Barracuda and Caratinga Development Project," by L.G.S. Messias dos Santos, Petrobras, originally prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission.

The Petrobras Barracuda and Caratinga project is a deepwater oil-production development in the Campos basin, offshore Brazil. The fields are in water depths of 600 to 1350 m and have reserves of approximately 1.75×105 m3 of oil and 12.5×109 m3 of gas. The project is being developed through a major turnkey engineering, procurement, and construction (EPC) contract. The EPC contract consists of converting two tankers into floating production, storage, and offloading (FPSO) units (the P-43 and P-48) capable of processing 2.385×104 m3/d of oil each; drilling and completing 54 wells; and developing the associated subsea system. This paper is an overview of the project.

Introduction

The Barracuda and Caratinga project was developed in two stages: a pilot system, followed by installation of the definitive system. The pilot system evaluated oil-production potential and gathered data characteristics of the reservoir and fluid properties. Operations began in September 1997 by exploring both fields through the P-34 FPSO. Eleven production wells from Barracuda and Caratinga fields were tied back to the FPSO, which had a liquid-processing capacity of 7.15×103 m3/d. This pilot system was demobilized in October 2002. The definitive system comprised the conversion of two very large crude carriers into two FPSOs: P-43 and P-48. In this stage, 54 wells were connected to these platforms through a subsea system. The development of the Barracuda and Caratinga definitive systems was combined into one unique project, and a single design was used to procure and build the twin FPSOs.

Field Background

As Fig. 1 shows, the Barracuda and Caratinga fields are 160 km east from Macaé (182 km northeast of Rio de Janeiro). The Barracuda field was discovered in April 1989, and the reservoir covers an area of 233 km2 with water depths ranging from 600 to 1100 m. The Caratinga field was discovered in February 1994, and the reservoir covers an area of 260 km2, with water depths ranging from 850 to 1350 m.

The proven reserves are 1.675×105 m3 of oil equivalent, and the total reserves are 1.8125×105 m3 of oil equivalent, according to SPE criteria. The average specific gravity of the produced oil from these fields is 0.91 g/cm3.

The pilot system provided oil-production estimates, gathered information to define the draining plan, and, hence, reduced the technical risks in the final conception. The pilot system also provided supplementary knowledge regarding the reservoirs, confirming information obtained from 3D-seismic and the exploratory wells. Use of the information and new technology reduced the number of wells needed from the predicted 129 vertical wells to 54 horizontal and multilateral wells.
Deepwater DST Planning and Operations From a DP Vessel
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90557, "Deepwater DST Planning and Operations From a DP Vessel," by Robert J. Stomp, SPE, ConocoPhillips Co.; Graham J. Fraser, The Expro Group; and Stephen C. Actis, SPE, Luke F. Eaton, SPE, and Kerry C. Freedman, ConocoPhillips Co., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

ConocoPhillips is developing the Magnolia field with a tension-leg platform (TLP) in 4,674 ft of water in the U.S. Gulf of Mexico (GOM). The field was discovered in 1999, and appraisal wells were drilled in 2000 and 2001. The precompletion and drillstem-test (DST) operations overcame several challenges, including frac packing a thick, fine-grained interval and well testing from a dynamically positioned (DP) semisubmersible drilling rig while simultaneously transferring produced hydrocarbons to a transportation barge moored to the rig.

Introduction

The Magnolia asset team was formed in 2001 before drilling the last appraisal well. Front end loading leading up to field sanction in December 2001 included concept selection and field development plans. The Magnolia field would be developed from a TLP to provide direct vertical access for recompletions, future sidetrack drilling, flow assurance, and cost-effective remediation.

The Magnolia development wells were predrilled (i.e., drilled from a mobile offshore drilling unit while the TLP was being built). The advantages of predrilling included minimizing capital exposure risks until shallow water-flow sands were isolated, allowing TLP well operations to be conducted with a lighter, lower-cost completion rig, which would further reduce the size and cost of the TLP hull; additional reservoir characterization before TLP installation; accelerating plateau production; and testing completion techniques in the precompleted well before “batch” completions of the remaining wells.

The B-25 reservoir, the primary pay horizon at the Magnolia field, was the zone selected for a DST. Zone B-25 is characterized throughout the field by its highly laminated sequences and large gross thicknesses. Whole-core data and fluid samples were obtained from the GB783-2ST2 appraisal well. Evaluation of the appraisal-well data classified the reservoir-rock matrix as a coarse siltstone with the average mean grain-size diameter of 41 µm. Overall, the mean grain-size diameters ranged from 25 to 71 µm in Well GB783-2ST2.

Test Objectives

The objective of performing a precompletion DST was to obtain critical information regarding completion design and reservoir issues. This information would be needed before the planned batch-completion program scheduled to begin in the fourth quarter of 2004.