bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Reserves/Asset Management (December 2011)
Authors: Hinkle Delores
Published: February 2015

Technology Focus

As a member of the JPT Editorial Committee, I am privileged to review papers presented at SPE events during the last year in the area of Reserves and Asset Management. I am always impressed by the highly skilled, innovative members of our Society who address the constant change in our industry in these papers.

Recently, many of the reserves papers have focused on changes in reserves and resource estimation resulting from the introduction of the Petroleum Resource Management System (PRMS) and the US Securities and Exchange Commission’s (SEC’s) Modernized Rules. Last year, many of the papers dealt with theoretical aspects of reserves estimation in unconventional plays. This year, most of the papers dealt with unconventional reserves, focusing on integration of theoretical and practical aspects of the engineering principles used to estimate reserves and resources. Several papers went full circle to address how issues around PRMS or the SEC’s Modernized Rules affect reserves and resource estimation in unconventional resources.

There was a similar shift in asset-management papers. Prior years were weighted heavily toward theoretical-optimization approaches, primarily focused on surface facilities. This year, there were many excellent papers addressing the practical application of those principles in technically challenging, high-cost environments. Integration of surface and subsurface components to improve efficiency was another recurring theme.

The fact that I could select only a few of the many outstanding papers that I reviewed highlights the importance of attending the venues at which these papers are presented. The insight provided during the presentation’s opportunity to ask questions yields valuable information that cannot be obtained by reading the paper alone. I selected the papers for highlighting and those recommended for additional reading with a view to the needs and interests of the membership of our global society. I hope I found something that will benefit each of you.

Reserves/Asset Management additional reading available at OnePetro: www.onepetro.org

SPE 128542 • “Greater Plutonio—Real-Time Reservoir Management in a High-Cost Deepwater Environment” by Dave Booth, SPE, BP plc, et al. (See JPT, September 2010, page 43.)

SPE 147623 • “Estimated Ultimate Recovery as a Function of Production Practices in the Haynesville Shale” by V. Okouma, Shell Canada Energy, et al.

SPE 142822 • “Tight Gas Modeling Frameworks for Improved Reservoir Management and Application to the Moxa Development Area” by Felipe Gallego, BP plc.

SPE 146788 • “Field-Development Optimization Under Uncertainty: Screening Models for Decision Making” by B.A. Ogunyomi, SPE, University of Texas at Austin, et al.
Production Acceleration or Additional Recovery? A Look Back at Three Published Field Trials - Long-Term Benefits of Improved Fracture Treatments
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144349, ’Production Acceleration or Additional Recovery? A Look Back at Three Published Field Trials To Determine the Long-Term Benefits of Improved Fracture Treatments,’ by K. Blackwood, SPE, Highmount Energy; P. Handren, SPE, Denbury Resources; and M. Chapman, SPE, T. Palisch, SPE, and J. Godwin, SPE, Carbo Ceramics, prepared for the 2011 SPE North American Unconventional Gas Conference & Exhibition, The Woodlands, Texas, 14-16 June. The paper has not been peer reviewed.

Improved fracture-treatment designs can increase production rates from many reservoirs. However, do these changes merely accelerate recovery, or is incremental production gained by changing the fracture design? The authors re-examined three tight gas case studies published in the past 10 years. The original studies were performed specifically to assess the effects of increased fracture conductivity on production. In all cases, the initial analyses documented that increasing conductivity appeared to increase production and recovery.   

Introduction

Since the first commercial hydraulic-fracture treatments in 1949, treatment designs have evolved from experimentation with massive hydraulic fractures to proppantless water-fracture treatments. While the production increase in the first few months or even the first year typically repays the cost of the conductivity upgrade, and is robust enough to make the decision to upgrade relatively simple, it is important to know whether this increase can be translated into additional ultimate recovery. If the ultimate recovery is also increased, then the economics of the completion upgrade may be even more favorable because it leads to a potential increase in reserves and drainage area per well, which in turn can lead to a reduction in the number of wells needed to drain the reservoir effectively.

In all cases, comparisons were made between high-quality ceramic proppants and either uncoated or resin-coated sand (RCS). In the past, conventional wisdom incorrectly suggested that hydraulic fractures in most tight gas wells behaved as “infinitely conductive.” This misperception arose from a poor understanding of proppant performance under downhole (realistic) conditions. Under realistic conditions, all proppants should be expected to lose more than 90% of their effective conductivity. By reanalyzing these case studies with longer term production results, the authors sought to determine whether the original conclusions still hold true, and whether confidence in the recovery projections can be determined.
Drilling Automation: An Automatic Trajectory-Control System
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 143899, ’Drilling Automation: An Automatic Trajectory- Control System,’ by Dimitrios Pirovolou, SPE, Clinton D. Chapman, SPE, Minh Chau, Hector Arismendi, Mbaga Ahorukomeye, and Juan Penaranda, Schlumberger, prepared for the 2011 SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, 19-21 April. The paper has not been peer reviewed.

Rotary steerable systems (RSSs) enable faster drilling, smoother wellbores, and extended-reach drilling. Still, a drilling assembly built around an RSS tool is sensitive to factors such as bit type, operating parameters, type of drilling fluid, lithology, and borehole diameter. Therefore, it is not always optimal for a human operator [typically a directional driller (DD)] to select and issue the correct commands to the drilling tool at the correct time. This situation becomes even more challenging when those decisions must be made in a matter of minutes.

Introduction

Typically, the DD monitors the path of a wellbore by use of stationary surveys, which include measured depth, inclination, and azimuth at the downhole survey station and the three computed Cartesian coordinates: true vertical depth (TVD), north/south (N/S), and east/west (E/W). Also, the DD sometimes uses continuous surveys (i.e., while-drilling vs. static surveys) to monitor the steering behavior of the drilling tools qualitatively. All this information is used to estimate the actual trajectory being drilled.

An RSS generally works by pointing or pushing the bit in a particular direction with a specified amount of force. The direction and force are set by issuing steering commands from the surface to the RSS tool. By downlinking steering commands while the well is being drilled, well paths can be created that follow a specific predefined plan. However, the steerability of the system can be affected by operating parameters such as weight on bit, rotary speed, and hardness of the formation being drilled.

In remote operations, when a DD may be monitoring or executing more than one job, the expertise generally must increase as the time constraints tighten. This requirement further necessitated tools that could assist the DD to maintain the desired plan.

Steering Application

Use of directional information enables correlating a drilled path to the RSS commands that were issued to drill the wellbore. Measurements can be from either a static or a continuous (while-drilling) survey. The problem has two main components and is diagrammed in Fig. 1.

Understanding the steering behavior of the drilling tool on the basis of steering commands (input) and actual steering responses (output)—Blocks 1 and 2 of Fig. 1.

Suggesting the optimal steering command to send to the RSS tool that will produce the desired steering response—Blocks 3 through 5 of Fig. 1.
Generating Electricity From Produced Water
Authors: Dahlheim Robin , Pike William J.
Published: February 2015

Technology Update

There are 823,000 oil and gas wells in the United States that coproduce hot water with their hydrocarbon output. This equates to approximately 25 billion bbl of water annually that could be used as fuel to produce up to 3 GW of clean electrical power. Not only would electricity generated from produced water add much needed electrical power, the life of many of these wells also would be extended and additional oil and gas produced.

A recent project funded by the National Energy Technology Laboratory of the United States Department of Energy conducted field demonstrations to determine the potential of generating electricity from hot produced water. Participants included Gulf Coast Green Energy (GCGE), ElectraTherm, Den-bury Resources, the Southern Methodist University (SMU) Geothermal Laboratory, the Texas A&M University petroleum engineering department, and Dixie Electric Cooperative.

The primary goal of the project was to prove the feasibility of interfacing the ElectraTherm Green Machine, a waste heat-to-power generator, with a producing oil or gas well. The project’s subsidiary goals were as follows:

Demonstrate the ability to produce electricity from waste heat in the produced water.

Show that producing electricity from produced water does not interfere with normal well operations.

Demonstrate how small oil and gas producers might increase their profitability by adding an income stream from power generation.

Determine the economic viability of generating electricity from waste heat in the produced water.

Determine whether the kWh output of electricity from the produced water has practical applications.

Identify the environmental impact of generating fuel-free, emission-free electricity from waste heat in the produced water.

It was important to hold a field trial to determine the extent of known factors that could not be identified or quantified in laboratory and bench scale runs. In addition, a field trial was necessary to identify potential corrective measures for new equipment designs and future produced water projects. The site chosen was a producing oil well, Denbury’s Summerland No. 2 well, near Laurel, Mississippi. In production for 5 years, the well has a high water cut and high produced water temperature. The well produces 100 BOPD and 4,000 BWPD from a depth of 9,500 ft with an electric submersible pump. The temperature of the produced water exiting the “knockout” tank at 120 gal/min is 204°F. The site has an ambient temperature range of 60°F to 105°F.
Mapping the Way to Optimized Production in Shale Formations
Authors: Neville Tom , Donald Adam
Published: February 2015

Technology Update

A two-step analysis can provide the key information needed to design optimal shale completions. The first step is to evaluate reservoir quality, which describes the hydrocarbon potential of a shale. The second step is to evaluate completion quality, which describes stimulation potential. Core analysis provides the basis to help calibrate the results of these two steps. The intersection of good reservoir quality and good completion quality leads to the best chance for success in shale completion. However, a failure to address both reservoir quality and completion quality will jeopardize the achievement of the ultimate goal: optimized production.

A shale reservoir by definition is a hydrocarbon source, reservoir, trap, and seal in a single package. Though similar in outward appearance, no two shales are alike. They are typically complex, heterogeneous rocks with extremely low permeability. Stress anisotropy is commonplace. This calls for the judicious integration of geology, petrophysics, geomechanics, and reservoir engineering to solve the puzzle that will enable the reservoir to yield its prize.

Reservoir Quality

To determine reservoir quality, defined as the hydrocarbon potential of a shale, it is necessary to quantify the amount of hydrocarbon in place and its deliverability to the fracture face. To do this, we must know the organic matter content and type, its thermal maturity, the effective porosity, fluid saturations, matrix permeability, and reservoir pressure.

The hydrocarbon in shale has evolved from thermogenic or biogenic alteration of kerogen, a fossilized organic material that is the source of oil and gas. In addition to providing the hydrocarbon source, kerogen plays a key role in developing reservoir quality in shales. Its degeneration creates pore space that makes up in part for the porosity lost during sedimentary compaction.

Because of its extremely high surface area and affinity for hydrocarbon molecules, this pore space is an excellent storage medium for gas, which becomes adsorbed onto the organic surfaces. In addition, free gas or oil may exist in larger pores, both within kerogen and between mineral grains. Understanding the mix between adsorbed and free hydrocarbons is essential for calculating total hydrocarbon content. Because of the role of kerogen in creating pore space and providing hydrocarbon storage, there is a strong correlation between kerogen content and total porosity, hydrocarbon saturation, and permeability. Therefore, kerogen content, or total organic carbon content (TOC), is an important indicator of overall reservoir quality.
Technology Focus: Reserves/Asset Management (December 2012)
Authors: Hinkle Delores
Published: February 2015

Technology Focus

While preparing for this month’s feature on reserves and asset management, I had the privilege of reviewing more than 100 abstracts from papers presented on the topic over the past year at SPE workshops and conferences. Interestingly, more than 10% of those abstracts addressed risk in some fashion. Integration was another common topic. Finally, I was a bit surprised by the number of abstracts that contained the word “practical” in their title. It struck me as a challenge we all face as part of our daily activities—integrating risk in a practical way.

The subject matter of the reserves papers I reviewed was widely varied but extremely useful. Papers addressed practical application of engineering processes to comply with the Securities and Exchange Commission’s 2009 modernized rules, innovative reserves forecasting approaches for unconventional reservoirs, the integration of geostatistics and reservoir modeling in reserves estimation, case studies where reserves were both under- and overestimated, and a variety of other topics.

As a topic, asset management also covers a wide range of issues. Papers continued to offer insight into field development optimization, techniques to manage risk, application of project management systems, innovative integrated asset models, and related topics. All of these papers provide in-depth, innovative analysis of issues resulting from the constant growth and development of our industry.

Choosing only four papers to be highlighted was a challenge. There were many, many quality papers covering current topics of interest. I tried to select papers that span the interests of the global industry and hit a balance between practical and theoretical information. The papers I selected for additional reading represent interesting case studies of somewhat innovative reserves estimation approaches. I hope you find both the highlighted papers and those for additional reading as interesting and thought provoking as I did.

Finally, anyone interested in more in-depth information on either reserves or asset management will find a wealth of additional information at www.jptonline.org, where the full-length papers of those synopsized here are available free to SPE members for 2 months. All of the papers contribute to the advancement of knowledge in our industry, and the authors who contributed to that cause by writing a paper should be congratulated.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 151045 Interference Study in Shale Plays by Ayantayo Ajani, The University of Tulsa

SPE 143843 Reserves Follow-Up Using an Integrated Deterministic/Probabilistic Approach by Hugo Araujo, Repsol-YPF, et al.

SPE 142936 Integrated Asset Model in Camisea, Peru by A. Downie, Baker Hughes, et al.

SPE 146788 Field Development Optimization Under Uncertainty: Screening Models for Decision Making by B.A. Ogunyomi, The University of Texas at Austin, et al.
Startup of Pazflor Giant Offshore Angola Tackles Challenges From Two Reservoirs
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23176, ’Startup of a Giant,’ by Arnaud Constant and Lionel Ramat, Total E&P Angola, prepared for the 2012 Offshore Technology Conference, Houston, 30 April- 3 May. The paper has not been peer reviewed.

The Pazflor development includes four reservoirs in Block 17 deep offshore Angola, which produce to a floating production, storage, and offloading (FPSO) unit through one Oligocene subsea loop and three Miocene lines connected to subsea separation units (SSUs) and subsea pumps, with associated-gas and water-injection facilities (Fig. 1). The startup of the Pazflor field required a response to three simultaneous challenges—startup of a large complex facility; flow assurance for two different reservoirs and oil qualities, an Oligocene field with light oil and Miocene fields with heavy viscous oil; and operating innovative Miocene subsea facilities with gas/liquid separation on the seabed.

Startup Preparation

Manning and Training. Although most of the production personnel were already experienced with FPSO operations, specific attention was given to training and a local training center at the Total E&P Angola offices was maximized.

One of Pazflor’s innovations was the design and use of an immersive training simulator (Fig. 2). This simulator was generated from construction of a 3D model and represents all the topside facilities with realistic rendering. In this 3D environment, operators move virtually through a simple interface, allowing for familiarization with their future facilities. Because all equipment is tagged, the operator can easily link his work documents, such as process flow diagrams and piping and instrumentation diagrams, to the actual FPSO environment before its completion or without actually being there. This simulator also can be used to simulate procedures execution, either individually or in a group, thanks to preloaded scenarios.

Startup Milestones and Initial Planning. The precommissioning, commissioning, and startup activities were structured according to milestones defined in the early project stage by field operations teams and included in relevant project-packages contracts. This breakdown by startup milestones was taken into account by the commissioning team from the early onshore commissioning stage and was later used to prioritize offshore construction, commissioning, and startup activities during the offshore campaign.

Eighteen startup milestones were considered initially, focusing on utilities, oil production, water injection, gas injection, and export systems and covering prestartup, startup, and normal- operations phases. The facilities were split into systems and subsystems, with a total of 669 subsystems, each linked to a specific startup milestone.
Geosteering With Sonic-Log Data
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146732, ’Geosteering With Sonic in Conventional and Unconventional Reservoirs,’ by Jason Pitcher, SPE, Jennifer Market, and David Hinz, Halliburton, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

Azimuthal variations with sonic logs have been observed in wireline and logging-while-drilling (LWD) data. Basic reactive-geosteering methods have been used, including drilling until a real-time sonic log detected a change in formation velocity then altering the wellbore trajectory. Taking sonic geosteering a step further has been proposed by providing real-time azimuthal images that show the velocities as they vary around the wellbore. These images can be transmitted at shallow and deep depths of investigation (DOIs) to determine how close an approaching boundary might be.

Introduction

LWD sonic tools have been used for simple geosteering since their introduction in the 1990s. The measurements typically were limited to the compressional-wave arrivals and (if available) refracted-shear-wave velocities. The use of real-time information was limited to simple correlation or direct-interpretation techniques. The practical use of these measurements was limited by the complexity of the measurement in terms of environmental conditions. These tools have found new application and use in recent work in shale-reservoir systems, including the Haynesville, Eagle Ford, Woodford, and Marcellus. In addition to using the compressional- and shear-wave data, these measurements are processed to provide dynamic data for Young’s modulus and Poisson’s ratio. The tools then are used to produce a real-time brittleness index that can be used to land and geosteer within the optimal production zone.

Measurement Considerations DOI/Depth of Detection. The sonic-tool DOI depends on the source frequency, formation resonant frequency, source/receiver spacing, and the configuration (i.e., monopole, dipole, or quadrupole) of the source. A general rule of thumb is to estimate the DOI as approximately one wavelength. Thus, for a given formation, a high-frequency source (10 kHz) would yield half the DOI of a low-frequency source at 5 kHz. Or, use of the same 10-kHz source in a 100sec/ft-velocity formation vs. a 50-sec/ft-velocity formation, the 50sec/ft-velocity formation would have a deeper DOI. This effect is complicated by each formation having a natural resonant-frequency range. In general, fast formations favor high frequencies and slow formations favor low frequencies. Annulus size also can affect the resonant frequency: A small annulus shifts the resonant-frequency range higher than a large annulus. Though the rule of thumb is a reasonable starting estimate, several factors can increase or decrease the DOI. Fig. 1 shows the effects of frequency and slowness on DOI.
Emerging Frontiers: The Arctic Frontier
Authors: Spath Jeff
Published: February 2015

President's column

One of the oil and gas industry’s most talked about emerging frontiers—but perhaps least understood in terms of familiar metrics—is the Arctic region. The Arctic refers to a portion of the globe above 66.5o N latitude that is roughly the size of Africa. Encompassing about 6% of the Earth’s surface, the Arctic consists of about one-third land, one-third continental shelf, and one-third waters deeper than 500 m (Budzick. 2009).

The Arctic contains portions of eight countries: Canada, Denmark (Greenland), Finland, Iceland, Norway, Russia, Sweden, and the United States. I cannot imagine any other region on Earth this large that has had so few efforts to explore for, develop, and produce hydrocarbons.

Arctic History

Indigenous people of the Arctic have known for centuries about oil seeps along the coastal plains, and even used pitch as a sealant on canoes. Back in 1789, oil seeps along the Mackenzie River, located within Canada, were reported by Russian settlers in Alaska (Bishop. 2011). Shell geologists first investigated Alaska’s oil potential in 1918. Sub-arctic oil was first discovered in Canada’s Northwest Territories in the 1920s. Russian geoscientists began exploring northern Siberia during World War II, and made their first major oil and gas discoveries there in the early 1960s (Bishop. 2011).

The first US federal lease sale on Alaska’s North Slope was held in 1958, and the first offshore lease sale in the Beaufort Sea in 1979. From the 1960s through the late 1980s, oil was discovered at Prudhoe Bay, gas was discovered in the Barents Sea, and the first exploration wells were drilled in the US Chukchi Sea.

After a period of inactivity due to low oil prices, exploration resumed in Canada’s Mackenzie Delta region in 2000, and in the US portion of the Beaufort Sea in 2005. The 5-month 2010 US moratorium on new deepwater drilling had an adverse impact on US Arctic drilling activity, and political and environmental opposition to Arctic exploration has been tougher since the moratorium was lifted, both in the US and elsewhere.

Nevertheless, due to growing demand and declining production from mature oil fields worldwide, international operators and governments have been initiating new Arctic exploration activities. This past summer, Norway opened a new area in the southeastern Barents Sea to offshore drilling. The service sector is following. Schlumberger and Baker Hughes, for example, opened new bases in the Norwegian town of Hammerfest, on the 71st parallel.

Size of the Prize

Any estimate of Arctic hydrocarbon resources suffers from considerable uncertainty, due to the limited amount of data from wells drilled throughout this enormous region.

In 2008, the US Geological Survey completed the Circum-Arctic Resource Appraisal. The study estimated total undiscovered conventional hydrocarbon resources of 90 billion bbl of oil, 1,669 Tcf of natural gas, and 44 billion bbl of natural gas liquids—a total of 412 billion BOE. That constitutes about 30% of the world’s undiscovered gas and 13% of the undiscovered oil (Bishop. 2011).
Displacing Diesel: The Rising Use of Natural Gas by Onshore Operators
Authors: Jacobs Trent
Published: February 2015

Natural Gas

Seizing on historic margins in domestic prices, North American oil and gas companies are increasing their efforts to use more natural gas and less diesel fuel to power their field operations. Until now, oil and gas companies have been ordering natural gas-powered rigs to qualify the technology through pilot programs in the field. However, “the inflection point” may have been reached, said Brad Bodwell, senior vice president of corporate and business development at Prometheus Energy. The company is one of the largest suppliers of liquefied natural gas (LNG) to the North American oil and gas industry and is entering a stage of “rapid growth” because of economic forces and major gains in domes-tic gas production. As the technology is evolving, so is its nomenclature. Operators and service companies are using two terms to describe engines that are fueled by a simultaneous injection of natural gas and diesel: “dual fuel” and “bifuel.”

Prometheus fueled up its first natural gas-powered generator sets on a drilling rig for operator EnCana in the Haynesville shale in mid-2010. “Since then, we have grown at a rate of about 80% per annum in terms of volume that we ship to our customers,” said Bodwell. In 2013, Prometheus had access to about 500,000 gal/D of LNG and was supplying seven operators in the United States and Canada. In total, North American LNG facilities produced 800,000  gal/D in 2013. New LNG facilities under construction and expansions of older facilities will bring the available supply of LNG up to 1.1 million gal/D by year-end. With several more plants already funded and expected to come online after 2014, the daily supply of LNG is projected to soar to 2.6 million gal/D after next year.

Bodwell estimates that natural gas is fueling as much as 7% of North America’s 1,100 horizontal drill rig fleets, but he predicts that share to soar to 50% within the next 2 years. There are environmental drivers as well since natural gas is the cleanest burning of all fossil fuels (Table 1). “You’re getting a fuel that is going to reduce your environmental footprint and, at the same time, it saves enough money that it pays for the cost of conversion,” he said. “So we don’t need to wait to achieve some sort of scale benefit or a government injection of capital into the industry to make it work. It is all stuff we know how to do.”
Searching for Opportunities in Environmental Trouble
Authors: Rassenfoss Stephen
Published: February 2015

Water Reuse

There are more than 4,000 miles of rivers and creeks in Pennsylvania as a result of the water draining out of abandoned coal mines. The orange-tinted water and rust-colored rocks are reminders of the damage going on since the days Pennsylvania mines powered the United States’ rise as a global industrial power.

Now producing natural gas by fracturing, the Marcellus shale is driving the state’s economy and those dead streams could present an unusual opportunity: offering both a source of much-needed water and a way to help clean up of waterways polluted by coal mine waste.

There is an exploration and production (E&P) company in the state, Seneca Resources, using the abandoned mine drainage (AMD) water for fracturing. By pumping as much as 500,000 gal/D of water from an old coal mine with low levels of sulfates, iron, and often other metals, it can improve the quality of the water downstream by taking those things out.

“There are a lot of opportunities in the southwestern part of the state,” because there are so many flooded old mine shafts draining into waterways, said Doug Kepler, vice president of the environmental engineering group at Seneca Resources. “There is a lot of activity. A lot of operators are looking into whether they can do that.”

Water used by Seneca requires little treatment because the sulfate and iron levels are low, but that is the exception in Pennsylvania, where chemicals leached from the water in old coal mines and from mining waste heaps can create metal-laden, acidic water that is deadly to fish, insects, and plant life in rivers.

While many E&P companies are interested in AMD water for fracturing, there are technical and legal obstacles to overcome.

Treatment methods are needed for water that is often highly acidic, loaded with sulfates, and high in iron or other metals. The cost of that water has to be competitive with relatively inexpensive freshwater sources, and that amount must cover the cost of disposal of any byproducts. And environmental regulators need to answer a critical question: If an oil company uses mine drainage for a time as a source of water for fracturing, will it be responsible for that water source forever?

The state has said it supports the use of AMD for fracturing, and Pennsylvania environmental regulators have supported a bill limiting liability for AMD use by the oil industry. The US Environmental Protection Agency has remained mute on liability questions related to AMD use, said Tom Gray, energy and natural resources manager at Tetra Tech, who delivered a presentation on the advantages of using mine water for fracturing. “To my knowledge, the EPA has never provided a direct written response.”
Recently Released Guidelines Supplement Petroleum Resources Management System
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 162520, ’New Guidelines Document Assists With PRMS Applications,’ by W. John Lee, SPE, University of Houston; Satinder Purewal, SPE, Energy Equity Resources; and D. Ronald Harrell, SPE, Ryder Scott, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.

The Guidelines for Application of the Petroleum Resources Management System (AG) document was issued in November 2011 to accompany and support the Petroleum Resources Management System (PRMS). The AG updates the 2001 document Guidelines for the Evaluation of Petroleum Reserves and Resources. This document will assist reserves evaluators throughout the world in understanding PRMS and how it should be applied in financial, regulatory, and reporting activities. Two new chapters have been added to the AG, eight others have been updated, and a comprehensive glossary has been added. 

Introduction

The AG was issued by SPE, along with the American Association of Petroleum Geologists (AAPG), the World Petroleum Council (WPC), the Society of Petroleum Evaluation Engineers (SPEE), and the Society of Exploration Geophysicists (SEG). It is available free to the public on the SPE website.

SPE has a long history of developing common standards for petroleum-resource definitions to provide consistency, transparency, and reliability to benefit stakeholders involved in international finance, regulation, and reporting.  In 1997, SPE and the WPC achieved a milestone in standardization when they approved the Petroleum Reserves Definitions. In 2000, SPE, WPC, and AAPG approved an updated version of the definitions, published as the Petroleum Resources Classification System and Definitions. In 2001, SPE issued Guidelines for the Evaluation of Petroleum Reserves and Resources, the predecessor of AG, to provide guidance for application of the 1997 and 2000 definitions. Then, in 2007, SPE, WPC, AAPG, and SPEE approved the PRMS. SEG subsequently endorsed PRMS.

PRMS has rapidly become the global standard for resources definitions and classification. For example, the US Securities and Exchange Commission used PRMS as a guide for its updated rules, Modernization of Oil and Gas Reporting, published 31 December 2008.

SPE and its sister organizations recognized that new guidelines were required to provide guidance for application of PRMS, replacing the 2001 guidelines. The 2001 guidelines were the starting point for AG, which has been updated by adding two new chapters and by modifying eight existing chapters. The two new chapters are

Assessment of Petroleum Resources Using Deterministic Procedures (Chapter 4)

Unconventional Resources Estimation (Chapter 8)
Probabilistic and Deterministic Methods: Applicability in Unconventional Reservoirs
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164820, ’Probabilistic and Deterministic Methods: Applicability in Unconventional Reservoirs,’ by C. Coll, SPE, and S. Elliott, BG, prepared for the 2013 EAGE Annual Conference and Exhibition/SPE Europec, London, 10-13 June. The paper has not been peer reviewed.

Reserves- and resources-evaluation methods in unconventional reservoirs are different from those for conventional reservoirs. Depending on the phase of the resource play, a deterministic, probabilistic, or hybrid method may be required, with the most effective method evolving from deterministic toward probabilistic as the resource play moves from the early phase to the mature phase. To define the best method to use in a particular area, the evaluator should first identify the phase of the resource play and evaluate the amount of data available.

Introduction

For unconventional reservoirs, classification systems similar to those for conventional reservoirs can be used (Fig. 1). These systems include prospective resources, estimated contingent resources at discovery, followed by reserves, with maturation linked to the phases of the resource play.

As the resource play matures and technologies are screened, the development projects are better defined. Sections of the estimated resource volumes may be assigned to the contingent- resources subclasses using, for instance, the SPE Petroleum Resources Management System (PRMS) that recognizes the technical and commercial maturation toward reserves. Because unconventional accumulations are pervasive and developed with high-density drilling, well counts are typically large, making statistical analysis of well performance feasible. As a result, probabilistic techniques may be more appropriate to understand the uncertainty ranges of estimated ultimate recovery (EUR) per well and associated confidence levels. Extrapolation of results requires careful consideration of the geology and engineering characteristics of a particular area to predict well productivity. This analysis could be more intricate than that for conventional reservoirs because of the short production history and the particularly complex displacement mechanisms that may be happening in these reservoirs.

For the estimation of resources in both conventional and unconventional reservoirs, it is important to understand the effect of reservoir uncertainties and development plans. Geological uncertainties such as gross rock volume, porosity, permeability, hydrocarbon saturation, and reservoir continuity have a large effect on in-place volumes. Engineering uncertainties (e.g., relative permeability, capillary pressures, viscosities, aquifer properties) affect the physical processes in the reservoir during the production of hydrocarbons, determining gas/oil recoveries and, finally, the ultimate reserves/resources.
Integrating Well, Reservoir, and Facility Management Improves Field's Production
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 16523, ’Oman's Large-Carbonate-Field Production Improvement Through Integrated Well, Reservoir, and Facility Management,’ by S.M. Al-Khadhuri, M.M. Al-Harthi, and A. Alkalbani, Petroleum Development Oman, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

A carbonate field developed by Petroleum Development Oman is one of the largest fields in the Sultanate of Oman and has been running for more than 4 decades. An integrated wells, reservoir, and facility management approach has been implemented to create more focus and discipline with the aim of achieving an efficiently monitored and controlled asset and highly synchronized multiteam actions. 

Introduction

The field is located in the north of the Sultanate of Oman, and it is one of Oman’s largest fields. The reservoir layers dip uniformly at 15° to the northeast (Fig.  1). The field is a highly complex carbonate reservoir of the Natih formation and is subdivided into seven units, Natih A through Natih G, and the Shuabia reservoir. It has been running since 1967 and continues to contribute significantly.

The development strategy began with natural depletion with vertical wells and followed with two mechanisms, gas/oil gravity drainage (GOGD) and waterflood. The GOGD process concentrates more on fractured reservoir rock, while the waterflood process targets the layers with a relatively low degree of fracturing.

The GOGD development consists of five crestal gas-injection wells and rows of down-flank producers that tap oil from a fractured oil rim. The reservoir pressure is managed by gas injection. The gas-injection rates are set to replace voidage and to maintain reservoir pressure. For the matrix wells, the reservoir pressure is managed by waterflood (water injection).

This combination of different drive mechanisms in a highly fractured reservoir that yields to interference and gas/water short-circuiting makes the management of the field very challenging.

To overcome these challenges, an integrated well, reservoir, and facility management strategy has been established in a way that ensures integration with multiple disciplines and uses many tools. As a result, an improvement in production has been seen that reflects successful implementation of the strategy.

Wells and Reservoir Reviews

Wells are reviewed on a yearly basis in order to have a systematic approach for reviewing wells. Approximately 26 sectors (more than 450 wells) from different reservoirs have been reviewed collaboratively. Multidisciplinary involvement from the well and reservoir management (WRM) team, the development and planning (DP) team, and the new oil (NO) team, and alignment to mature identified activities, played a crucial role in effectively sharing ideas and lessons learned and implementing activities.
The Business Case for Process Safety
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 157592, ’The Business Case for Process Safety,’ by Scott Berger, Center for Chemical Process Safety, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed.

Over its 27-year history, the Center for Chemical Process Safety (CCPS) has observed that the first step toward implementing a strong process-safety-management program is obtaining top-management commitment. The CCPS has learned that communicating the business case for process safety is an important part of the process of obtaining this commitment. Using a fictional incident as a case-study example, this paper will illustrate that process safety can have financial, as well as ethical and professional, benefits.  

Introduction

The CCPS has identified four dimensions in which process safety can influence the value of the business:

Corporate responsibility

Business flexibility

Risk reduction

Sustained value

These dimensions affect financials in both quantitative and qualitative ways, addressing both cost savings and revenue enhancement. Table 1 illustrates the alignment of these four dimensions. 

The Incident

One January day several years ago, a major process vapor line ruptured in the core unit of the Phlogiston Chemical Company Western Plant. Minutes later, a serious explosion ripped through the unit. The blast wave dislodged a nearly empty vessel, ripping it from its connecting piping. The vessel contained a toxic material that dispersed downwind, along with thick black smoke from the fire that resulted from the explosion.

The company’s emergency-response team, along with local firefighters, responded rapidly. While residents took shelter, the responders set up a water curtain to mitigate the toxic release and worked to extinguish the fire. Unfortunately, when the response team sounded the all-clear signal 4 hours later, nine workers and one town resident were dead. Another 25 families gave thanks that their loved ones would recover from their injuries.

Ultimately, investigators determined that a main flange in the vapor line had been bolted incorrectly and that the mounting brackets of the vessel containing the toxic material had corroded. A root-cause analysis showed that the technician assigned to the plant’s mechanical-integrity program had simply been “checking the boxes” for the previous 5 years and that management never spot-checked the mechanical-integrity program to verify that it was being practiced as written.
Abnormal-Situation Management in Offshore Operations
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166584, ’Abnormal-Situation Management and Its Relevance to Process Safety for Offshore Operations,’ by Dal Vernon Reising and Peter Bullemer, Human Centered Solutions, and Bruce Colgate (retired), prepared for the 2013 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 3-6 September. The paper has not been peer reviewed.

The Abnormal Situation Management (ASM) Consortium performed a root-cause analysis on 32 incident reports gathered from public documents and member companies. The analysis identified common failure categories and manifestations in these incidents. Consequently, the consortium completed three case studies on potential deployment solutions: one supporting better shift-handover communication, a second supporting better alarm-flood situations, and a third supporting better situation awareness by use of overview displays using qualitative gauges. 

Introduction

The ASM Consortium has been working for almost 20 years with an emphasis on human-factor engineering to address process-safety and operational challenges for downstream hydrocarbon-processing and petrochemicals companies. These consortium members have jointly invested in research and development to create knowledge, tools, and products designed to prevent, detect, and mitigate abnormal situations that affect process safety in the control/operations environment. The consortium has placed a continual emphasis on the humans that use automation and technology to operate the production processes, focusing extensively on human factors, human reliability, and process safety. Recently, the consortium has expanded its focus to upstream enterprises, with many of the operating company members having extensive oil and gas businesses.

What Are Abnormal Situations?

The ASM Consortium has defined abnormal situations as “undesired plant disturbances or incidents with which the control system is not able to cope, requiring a human to intervene to supplement the actions of the control system.” An abnormal situation could be a simple upset condition quickly recognized and rectified by operator action, or an abnormal situation could escalate to a critical process-safety incident, where a safety system must be engaged for an emergency shutdown and evacuation is required. The objective of ASM is to bring the process back to normal before safety-shutdown-control systems or other safety-protection systems are engaged.

This definition is specifically used to distinguish between normal, abnormal, and emergency situations from the perspective of console operations. Often, operator error is blamed for causing incidents, and companies rush to increase training as a panacea. The work of the consortium has shown that incidents are caused by a multitude of factors, and solutions to address incidents need to consider the human operator’s role, the technology involved, and the system design, as well as the environment.