bluuebunny/crossref_metadata_2025 huggingface dataset:
SPE's Distinguished Lecturer Program Celebrates 50 Years
Authors: Beckwith Robin
Published: February 2015

Distinguished Lecturer Program

SPE’s Distinguished Lecturer Program has flourished throughout its 50-year history, consistently receiving accolades from SPE members. Since 1961, more than 800 Distinguished Lecturers have traveled far and wide, many giving their presentations 30 or more times—the living embodiment of SPE’s mission as they disseminate technical knowledge concerning the exploration, development, and production of oil and gas resources, and related technologies at SPE section meetings. Twenty-one Distinguished Lecturers have also served as SPE presidents. Distinguished Lecturers continue to be a great draw for section programs, providing content that meets SPE member needs for substance and quality.

Not only are Distinguished Lecturers in constant demand, but SPE members are eager to serve as lecturers. “I feel a little guilty,” said Michael Byrne, global technical head, formation damage with Senergy and a Distinguished Lecturer during 2009–10, “because I thought this was a way to give something back to SPE, but in fact what I found was I got a lot more than I think I gave.”

Giovanni Da Prat, president of Da Prat Consulting and Distinguished Lecturer during 2003–04, echoed this sentiment: “I feel that I gained enormously from the experience of meeting people from other SPE sections, reflecting wells and reservoir conditions different than in my country.”

Participants often express that their presence in remote SPE sections fosters a sense of belonging to a worldwide technical community. “I believe the success of the program is that Distinguished Lecturers see themselves as ambassadors of SPE,” said Thomas Blasingame, professor of petroleum engineering at Texas A&M University. “I also believe that Distinguished Lecturers try to bring a sense of being in the SPE family. Despite all my travels, I never felt alone or out of place.”

The First Decade

When SPE was established in 1957 as one of three semiautonomous societies within the American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME), its membership was 12,500. Over the next few years as it grew to almost 15,000 members SPE began to put more emphasis on the dissemination and exchange of industry-related experience and technical information. A key aspect of its maturation came from the desire of the SPE Board of Directors to secure excellent speakers for local SPE section meetings.
Rupture Disk Valve Improves Plug-and-Perf Applications
Authors: Arguijo Andrew L. , Morford Lee , Aviles Isaac , Baihly Jason
Published: February 2015

Technology Update

Plug-and-perf completions have proved to be the most flexible multistage well completion schemes. The main reason is that each stage can be perforated and treated optimally because options can be exercised right up to the moment the perforating gun is fired. This allows the engineer to apply knowledge from each previous stage to the stage under treatment. For example, using real-time microseismic fracture mapping techniques provides a view of where previous fractures have propagated, which enables adjustments to be made to perforating depth and pumping schedules for subsequent stages.

Some people have argued that the plug-and-perf technique is too time consuming and that it is too slow at the start because of the need to run the first stage perforating guns in with coiled tubing, stick pipe, or a downhole tractor, thus adding an unnecessary expense.

A new technique introduced by Schlumberger adds significant operating efficiency and lowers the cost of cemented, multistage fracturing by eliminating the initial perforating run. The technique uses the KickStart pressure-activated rupture disk valve to enable the first stage treatment to be combined with casing operations. In addition to reducing downtime, the technique has been shown to lower fracture initiation pressure, thereby eliminating the risk of closed perforation tunnels caused by shale swelling, and to increase the likelihood of fracturing the stage to completion.

The extensive study of geomechanics has shown that rock formations fracture at their weakest point and that the weakest point aligns with the plane of maximum horizontal stress whenever the overburden (vertical) stress exceeds lateral stresses, which occurs most of the time. The pressure-activated rupture disk valve has a unique helical port design that exposes the formation outside the casing to fracture pressure, thereby ensuring that the fracture will align with the maximum horizontal stress plane and propagate at the weakest point in the formation. A major benefit of this alignment is the reduction of tortuosity at the fracture initiation point, which significantly reduces the probability of a premature screenout of the initial fracture treatment at the toe of the completion.
Reduced-Emission Completions Improve Safety, Decrease Footprint
Authors: Dunnahoe Tayvis
Published: February 2015

Green completions

In its proposed New Source Performance Standards (NSPS) established in August 2011, the EPA estimated that, of the 25,000 new and modified fractured gas wells completed each year, approximately 3,000 to 4,000 currently employ reduced-emission completion (REC). Once finalized, the new rule will increase this number to more than 21,000 RECs annually as operators comply with the proposed NSPS. By 2015, every hydraulically fractured well will be required to use a green completion to capture and measure all oil and gas released during the flowback and drillout phases.

Typically, the gas/liquid separator installed for normal well flow is not designed for the high-rate, four-phase (gas, hydrocarbon liquid, water, and sand) flow of a typical shale well. A common practice for the initial well completion has been to produce the well to a pit or tanks where water, hydrocarbon liquids, and sand are captured and slugs of gas vented to the atmosphere or flared. Completions can take anywhere from one day to several weeks, during which time a substantial amount of gas may be released to the atmosphere or flared.

Green completion equipment is only necessary for the time it takes to complete the well. Operators typically transport this system from site to site to be used in a number of well completions, often on a truck-mounted skid. Don Atencio, manager at Fracmaster, said, “The setup for a green completion depends on the area and the type of well you are completing.” There is no set amount of equipment that is required.

An REC can be performed with one self-contained unit, or it can be set up using individual components. Each job is based on need, the volume of gas and fluids being produced, and the size of the pad. For a multiwell pad, the equipment set up can be extensive. “Some of the work we are doing in New Mexico involves three major pieces of equipment that are too big to load onto one skid,” Atencio said.
Middle East Attacks Raise Cyber Security Questions
Authors: Henni Abdelghani
Published: February 2015

Cyber security

Cyber attacks on Saudi Aramco and Qatar’s RasGas have forced oil and gas companies in the Middle East to heighten their computer system security controls to prevent security breaches and to protect their assets. Companies operating in the region are also reviewing their security software and firewalls to ensure that they are updated and able to withstand more attacks.

Both Saudi Aramco and RasGas were hit with the Shamoon (also known as Disstrack) trojan, which led to serious network disruptions. Shamoon takes control of a system connected to the Internet before spreading to personal computers in an organization’s network. The second stage overwrites files and the master boot record of a machine, which makes a personal computer unbootable. Computer systems at Saudi Aramco and RasGas were shut down for weeks into September after the first attacks in mid-August, but oil and gas production was not affected. Kuwait Petroleum was not hit by the attack but immediately increased security to protect its information technology systems.

The attacks were similar to those carried out against Iranian computers earlier this year that wiped numerous hard drives. Security officials said they believe the attacks were unrelated and believe it was a copycat virus.

After the attacks, Saudi Aramco organized an information technology cyber security and protection response workshop in September, inviting representatives from the Saudi Arabian government and the country’s largest corporations to discuss the issues and share best practices.

Saudi Aramco talked about its reaction to the cyber attack and shared information about its crisis management and response strategies to counter cyber security threats. “We always realized that no matter what protections we had in place, we cannot be 100% sure that our information systems will not be breached,” said Khalid Al-Falih, president and chief executive officer of Saudi Aramco. “So we developed incident response plans to deal with different kinds of scenarios and contingencies. What happened to us can happen to anyone. Working together, we can increase our collective defense.”
Technology Focus: Field Development Projects (October 2012)
Authors: Rebelo Mauricio P.
Published: February 2015

Technology Focus

During the past years, several discoveries have been made in deep and ultradeep waters around the world. Many development projects are ongoing, and exploratory campaigns are increasing in this type of play. This latter factor will certainly result in new discoveries; it has already been seen in the presalt in Brazil, the Lower Tertiary in the deep water of the Gulf of Mexico, and the fields off the coast of West Africa.

One of the challenges faced by the operators is making the appropriate selection for a field development plan. This is certainly the key to a successful project, requiring several studies by the operators to allow the technical groups to understand the complexity of the reservoir.

The drilling costs in deep water continue to increase every day and represent the bigger portion of the capital expenditures for deepwater-field development. Therefore, having a good knowledge of the reservoir will help define the well design and architecture, optimizing the costs and maximizing the oil recovery.

The papers selected for this month’s issue are related to deep- and ultradeep-water field development projects and are good examples of how operators are working on studies to help make the correct decision for the development plan to be selected. Please enjoy your reading.

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

OTC 22993 The Who Dat Development: Evolution of a Project From Lease Sale to First Production by Rick Fowler, LLOG Exploration, et al.

OTC 23172 Pazflor, a Major Step for Angola by Gaspar Martins, Sonangol

OTC 22997 Overcoming Field Development Challenges in Depleting Ultra-HP/HT West Franklin Field by Slobodan Jezdimirovic, Total E&P, et al.

SPE 147956 Modeling of a New Field Development Plan for a Giant Offshore Oil Field in the UAE by S. Bachar, Zakum Oil Development, et al.
Technology Focus: Tight Reservoirs (October 2012)
Authors: Kubala Gregory
Published: February 2015

Technology Focus

The wave of technology change in tight-reservoir exploration and production continues to gather momentum, with completion strategies and hydraulic-fracture stimulations customized to reservoir heterogeneity and quality as the central drivers for improvement. Another noteworthy driver for technology change is environmental-footprint reduction. Proppant-placement technologies now provide production enhancement with reduction in sand and water consumption. Other technologies are enabling the reuse of produced and flowback waters.

Tubular, materials, and fluids technologies are evolving to meet the challenges encountered in tight-reservoir drilling, especially for high-temperature or high-pressure applications in “soft” rock. Completion products and practices, such as casing selection, wellhead selection, and numbers of perforations and their placement with regard to the planned fracturing stages, are evolving to enhance production from multistage-fractured, long horizontal wells while reducing the associated costs. Thanks to basinwide reservoir and microseismic data, hydraulic-fracture modeling is evolving to rationalize the apparent contradiction between anecdotal evidence and established theories for (1) fracture initiation, growth, and closure; (2) fracturing-fluid functional requirements; and (3) proppant selection, transport, and placement.

At the same time, with reservoir-specific formation and production data, there continues to be growth in the understanding of production mechanisms and their relationship to the various formation types and understanding of geomechanical responses that result from hydraulic fracturing. Examples of such understanding are changes in permeability influenced by pore volume, near-wellbore choking as a function of rock properties, and slip/shear response as a function of rock properties.

Plenty of progress remains to be made in linking together the production mechanisms, geomechanical responses, and hydraulic-fracturing models into an effective knowledge base. Opportunities still exist in then using this knowledge base to create workflows for better completion strategies and hydraulic-fracture stimulations. This month’s feature presents papers and a reading list that reflect several of these observations.

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

SPE 148940 Stimulation's Influence on Production in the Haynesville Shale: A Playwide Examination of Fracture-Treatment Variables That Show Effect on Production by Neil Modeland, Halliburton, et al. (See JPT, March 2012, Page 62.)

SPE 155640 Gas Flow Tightly Coupled to Elastoplastic Geomechanics for Tight and Shale Gas Reservoirs: Material Failure and Enhanced Permeability by Jihoon Kim, Lawrence Berkeley National Laboratory, et al.

SPE 147462 Improving Fracture-Initiation Predictions on Arbitrarily Oriented Wells in Anisotropic Shales by Romain Prioul, Schlumberger-Doll Research, et al.

SPE 155756 A Pore-Scale Gas-Flow Model for Shale-Gas Reservoir by Vivek Swami, University of Calgary, et al.
Optimizing Frac-Pack Completions in Multilayer and Low-Stress-Contrast Zones
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 151870, ’Systematic Approach Used to Optimize Frac-Pack Completions in Multilayer and Low-Stress-Contrast Environment Encountered in the Usan Field,’ by M. Prada, SPE, Chevron; J. Hernandez, SPE, and R. Bouget, Total; and S. Green, SPE, Schlumberger, prepared for the 2012 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 15-17 February. The paper has not been peer reviewed.

The deepwater Usan field, approximately 100 km south of Port Harcourt, Nigeria, has multiple oil-bearing turbidite sands of varying thickness and permeabilities that are separated by massive and thin shale intervals, making the selection of completion intervals difficult. Fracture-height confinement is challenging because of the small stress contrast between the sand bodies and the bounding shales and the stress-field variability in a highly compartmentalized environment. Frac-pack completions were used in this field. The main challenges, lessons learned, and improvement opportunities captured during the first 2 years of the Usan completions campaign are presented.  

Introduction

The Usan oil field is offshore Nigeria in Block OML 138, approximately 60 km south of the existing Amenan field (Fig.  1). Water depth ranges from 660 to 820 m. The Usan project is a stand-alone development and will comprise more than 40 subsea wells (oil producers and water/gas injectors) connected to a floating production, storage, and offloading (FPSO) facility. Oil producers are completed as cased-hole frac packs (CHFPs), and the water and gas injectors are openhole expandable-screen (OHES) completions. Some of the oil producers and gas injectors are equipped with surface-operated downhole flow-control valves to enable real-time reservoir management and production optimization. 

Reservoir Aspect

These Usan Tertiary reservoirs have multiple turbidite-sand bodies of 3- to 30-m thickness with permeability up to 3,000 md and are separated by 3- to 20-m-thick shale layers, making them difficult to complete. In a smaller scale, some of the reservoir targets have very-thin (<5 cm) to medium (5–10 cm) laminated shale intercalations that are difficult to predict and exclude from the completion interval. Because of the strong compartmentalization, there are important variations of fluid parameters between reservoir levels and panels. Oil density ranges from 20 to 40°API, and in-situ viscosity ranges from 0.2 to 4 cp. Oil is slightly undersaturated, with an average reservoir pressure 10 to 20 bar above saturation pressure.
Emerging Frontiers: Focus on East Africa
Authors: Spath Jeff
Published: February 2015

President's column

Over the next year, I will use this monthly column to offer my thoughts on emerging frontiers—geographic as well as techno-logical. In some columns, I’ll take a look at the hottest new oil and gas regions around the world, state-of-the-art technologies that make it possible to succeed there, and the role that SPE is playing in the region. In other columns, I’ll consider a variety of broader, cutting-edge trends and developing technologies, such as big data and the evolving face of education, and the role they are playing within our industry as a whole and, more specifically, within SPE.

East Africa

To kick off, consider one of the most dynamic oil and gas regions to emerge, quite unexpectedly, in recent years—east Africa, in particular Mozambique, Tanzania, Kenya, and Uganda.

While exploration in this area dates back to 1904, recent massive natural gas discoveries by Anadarko, ENI, Statoil, and others have catapulted Mozambique and east Africa into the spotlight. Since 2010, for example, an estimated 100 Tcf of recoverable gas reserves have been discovered offshore Mozambique alone (US Energy Information Administration, 2013). Exploration success combined with greater political stability and reasonable commercial terms has brought an unprecedented surge of investors, operators, service companies, and associated vendors into the region.

One of the more significant challenges to supporting the influx of oil industry expatriates to east Africa is inadequate infrastructure in all of these countries, especially in Mozambique, which has had little to no investment following decades of civil war. With such a promising future, however, the number of hotels, restaurants, and international banks is growing daily. In a recent visit to Maputo, the capital of Mozambique, I heard people complaining about the novelty of traffic congestion—a sign of development. Nevertheless, the country has a long way to go. Despite being one of Africa’s fastest growing economies over the last decade, Mozambique still ranks 185 out of 186 on the United Nation’s 2012 Human Development Index—below Sudan and Afghanistan (United Nations Development Programme, 2012).

Local Talent Needed

Apart from infrastructure, perhaps the greatest hurdle in developing newly discovered gas resources is the scarcity of local engineering talent. Most students in east Africa leave the country or the continent to obtain degrees in oil and gas. As you can see from Fig. 1, there is a dearth of oil and gas universities in sub-Saharan Africa overall, and east Africa in particular. Yet these nations desperately need to train professionals in the oil and gas disciplines, especially petroleum engineering. As an example, Kenya’s Ministry of Higher Education noted that, following its first commercial discovery of oil in 2012, the country needs at least 30,000 engineers to realize its goal of becoming a middle-income economy by 2030 (Wanga, 2013). Imagine how many engineers the other countries in east Africa will need to achieve their potential.
Comments: Mexico's Oil Reform
Authors: Donnelly John
Published: February 2015

Editor's column

Momentum appears to be growing for a proposal that would more fully open Mexico to outside oil and gas investment. The move could offer attractive upstream opportunities to operators and the service sector, and intends to rescue Mexico’s steeply declining production.

The proposal by Mexican President Enrique Pena Nieto lacks critical details for investors and is politically controversial, but it marks the most significant step to loosen restrictions on foreign investment in decades. Mexico nationalized its oil industry in 1938, and its constitution states that ownership of natural resources belongs solely to Mexico. Oil production and reserves have been falling sharply, however, and now pose a threat to the country’s economic health. The proposed reform addresses the downstream as well as power sectors, but the changes designed for the upstream are the most contentious.

Although Mexico is the 10th largest oil producer in the world, its output last year of 2.6 million BOPD represents a 20% decline since 2002. In July, oil production dipped to its lowest level since 1995. Aging oil fields and underinvestment have contributed to the fall, as the government leans heavily on state oil company Pemex for revenue that a private company likely would reinvest in oil infrastructure. The once prolific Cantarell field, the world’s third largest when it was discovered in 1976, produced 400,000 BOPD in July, compared with a peak of 2.3 million BOPD in 2003. The new proposal argues that the oil sector needs additional investment, technology, and expertise to fully exploit promising deepwater and shale opportunities.

The proposal would allow the government to offer profit sharing to private operators. However, it is unclear whether operators would be allowed to book reserves, which could be a deal breaker. A foreign company’s share would be based on a percentage of production relative to the oil price.

The president contends that his plan would increase oil production from the current 2.5 million BOPD to 3 million BOPD by 2018 and 3.5 million BOPD by 2025. Of particular interest is exploration in the deepwater Gulf of Mexico, where most of the country’s future oil potential appears to lie, which represents both financial and technical challenges, and northern Mexico, where shale basins contain an estimated 60 billion BOE. The shale basins are just south of the Eagle Ford Shale development in south Texas, which has contributed to the “shale revolution” in the United States.

Oil nationalism in Latin America runs strong. But Brazil state oil company Petrobras blossomed after it was partially privatized in 1997. After it opened its oil sector to private participation, Brazil went from a net oil importer to self-sufficiency in just a few years and production rose from under 1 million BOPD to the current 2.4 million BOPD. Its recent pre-salt discoveries may enhance its output significantly. The development of those resources could propel Brazil into the league of the world’s largest oil exporters.
What Is Next for Intelligent Energy?
Authors: Al-Mulhim Waleed , Mubarak Saeed M. , Bonilla Juan Carlos G.
Published: February 2015

Guest editorial

In recent years, many companies in the oil and gas industry have been making steady progress employing digital oilfield (DOF) solutions to improve operations through better data capture, visualization, analysis, and automation. As more implementations provide value to particular fields or assets, a question remains of how they can be leveraged as a whole to provide aggregate value at the business portfolio or corporate strategy levels. The large volume and detail of information that DOFs generate, not only in terms of data, but also decision outcomes, interpretations, and knowledge, both tacit and implicit, contribute significantly to a company’s intellectual capital.

Looking at the business case, asset-level business drivers are normally defined by considering short-term benefits in light of immediate challenges. Because of the varied production environments and diverse approaches associated with DOF implementations, determining return on investment and value for an organization’s overall production business is difficult at best; it is analogous to an “apples vs. oranges” comparison of assets. For companies actively pursuing multiple DOF programs, managing commercial uncertainties is, therefore, a key challenge for allocating resources, defining a coherent vision, and ultimately determining the appropriate level of commitment, financial or otherwise.

Applying this perspective, there is a clear opportunity, and corresponding challenge, to scale the DOF value proposition by smoothly integrating independent digital assets into a cohesive system by delivering a smarter, more comprehensive view of a company’s business portfolio. Toward this end, several key concepts and issues should be considered carefully in order to understand the implications of each implementation as the first step toward corporate value realization.

Strategic Business Intelligence

DOF solutions leverage real-time asset awareness, in combination with intelligent analytical tools and collaborative business processes, to continuously optimize production. Data is gathered and manipulated to create information, which in turn develops into knowledge for decision support. Knowledge is the critical piece and having the ability to exploit it to the benefit of the organization should be fundamental. This is the essence of business intelligence and is at the core of the DOF value proposition.
Steerable Liner Trims Nonproductive Time and Boosts Oil Recovery in Problem Well
Authors: Biscaro Enrico
Published: February 2015

Technology Update

To compete successfully in the global energy market, exploration and production companies must operate efficiently, economically, and safely in increasingly difficult environments. Subsalt applications, unstable coal and shale layers, tar zones, depleted zones, and formations with variable flows and pressures are among the problems routinely encountered that must be overcome.

In these problem zones, nonproductive time (NPT) of 30% in drilling operations has become commonplace in many areas, with 45% reported in some wells. Wellbore instability appears to be the main cause of NPT. Some operators report that it accounts for more than 40% of their NPT and approximately 25% of drilling costs in difficult wells. NPT related to wellbore stability in these applications ranges from several hours to several weeks in just one section, and costs run from thousands to millions of dollars.

Other causes of NPT in these wells include narrow drilling margins and lost circulation. In many situations, operators must compromise ideal well placement to avoid troublesome formations, leaving millions of barrels of oil in the ground.

Baker Hughes recently developed the SureTrak steerable drilling liner (SDL), the industry’s first SDL system that has been used to drill, evaluate, and place a liner to total depth (TD) in complex, 3D directional wells in a single run (Fig.  1). The advent of SDL technology mitigates the risk of drilling through problem zones or formations and creates opportunities to maximize reservoir potential by reaching reservoirs that were previously unreachable. The SDL system was recently used in an innovative openhole patch application that saved drilling time and significantly increased oil recovery in a problematic North Sea well.

Technology Evolution

The concept of drilling with a string of casing rather than conventional drillpipe has existed since Reuben Baker’s original 1907 patent for a casing shoe used in cable tool drilling. In its most basic form, casing is driven into soft formations by circulating and rotating. The addition of basic cutting structures on the casing shoe facilitates the procedure. It also allows harder formations to be drilled and enables the shoe to be drilled out conventionally afterward so that drilling can continue. Various casing drilling technologies and approaches have been used throughout the decades; in general, the main goal was to reduce drilling time by combining the casing and drilling into a single operation.

As the need arose for more power to the bit in high-torque operations, a system was developed with the motor installed inside the casing. However, only minimal steering was possible with this system, which led to the emergence of steerable casing while drilling (CWD).
The Next-Generation Water Filter for the Oil and Gas Industry
Authors: Dejak Michael
Published: February 2015

Young Technology Showcase

Many segments of the oil and gas production industry need improvements in water filtration over traditional methods. This is true because of the trend toward oil and gas production in tighter, less permeable reservoirs and the greater use of enhanced oil recovery (EOR) techniques, many of which involve injecting water into the oil reservoir. To protect the integrity of such reservoirs, the amount of solids introduced into the reservoir through water injection, even solid particles down to 1 µm in size, must be minimized. Conventional filtration methods generally do not meet this requirement. An enhanced filtration technology known as Spectrum Plus Filtration, which incorporates the use of granular micro media, has been proven in other industrial applications and has been introduced and successfully proven in the treatment of produced water. This technology holds the promise of meeting the new requirements while being economical and robust.

New oil production practices often involve more water treating and more water injected into wells and reservoirs that are tighter and more costly to develop. This means that there is a greater concern about injecting excessive amounts of solids into these wells and reservoirs. The consequences of this can be

Reservoir plugging, which can cause production declines or inadvertent fractures

Greater frequency of well and reservoir plugging requiring workovers, acid treatments, and new wells with the associated production loss

Reduction in production or in the total recoverable potential of the reservoir

Souring of wells through introduction of sulfur-reducing bacteria from water injection

In response to the concerns that solids injected into wells can have, specifications for the water quality being injected into such wells are increasingly being defined by a particle size cutoff at about 2 µm, with many specifications requiring that 95% to 98% of the particles greater than 2 µm are removed.

Some other new production practices involve other water conditioning process equipment, which in turn requires excellent filtration for it to perform properly.

Traditional Water Filtration Methods

Table 1 lists some traditional water filtration technologies and their limitations in meeting the new requirements.
Addressing Gaps in Water Treatment Technology
Authors: Rowland Gina , Walsh John
Published: February 2015

Management

As demand for energy continues to rise and conventional sources become more scarce, oil and gas companies are under pressure to pursue production through unconventional methods and enhanced oil recovery (EOR) technologies. Nearly all unconventional and enhanced recovery methods involve significant amounts of water and, therefore, specific technical and management challenges related to water.

Not only does this trend have significant implications for the water treatment business, it also calls for a new level of cooperation between the industrial water treatment sector and the oil and gas industry. With the growing and urgent need for better, commercially effective ways to handle produced water from unconventional production, the question of how the oil and gas industry will be able to access the best that the water treatment industry has to offer now shows the beginnings of a possible answer. The water treatment industry has started to appreciate the complexity of water challenges in the oil and gas industry. Likewise, the latter has begun to look to the former for solutions.

This article will review the market drivers and environmental risks behind the rising significance of water treatment in the industry, discuss how some oil and gas producers currently look at the problem of persistent water treatment technology gaps, and point the way forward for better professional collaboration among stakeholders and the development of business opportunities. The time is right for energy companies to see that they have synergies with water companies and for both sectors to recognize that the challenges of water scarcity and environmental protection are, if handled appropriately, opportunities.

Market Drivers

The current growth in the water treatment market is directly linked to oil prices and demand. With Brent crude holding just above USD 100/bbl and long-term projections predicting that oil will remain a significant portion of the energy mix, energy producers are approaching the problem of declining production from older reservoirs by extracting as much oil as possible from existing assets through the application of EOR methods, most of which require the injection of large amounts of water (miscible gas being the main exception). Extracting oil from mature fields also means that oil companies have to handle the problem of an increasing water/oil ratio (WOR) in the production process (Fig 1). Water production estimates were approximately 250 million B/D in 2007 for a WOR of approximately 3:1 (SPE, 2011); WOR is expected to reach an average of 12 for onshore crude oil resources by 2025 (GWI, 2012).
Shale Development Plan Blends Fracture, Reservoir, and Geomechanics Modeling
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164018, ’Integration of Fracture, Reservoir, and Geomechanics Modeling for Shale Gas Reservoir Development,’ by Jugal K. Gupta, SPE, Richard A. Albert, SPE, Matias G. Zielonka, SPE, Yao Yao, SPE, Elizabeth Templeton-Barrett, SPE, Shalawn K. Jackson, SPE, and Wadood El-Rabaa, SPE, ExxonMobil Upstream Research Company, and Heather A. Burnham, SPE, and Nancy H. Choi, SPE, XTO Energy, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed.

A multidisciplinary approach integrates fracture characteristics, reservoir production, and stress-field evolution to design and optimize the development of unconventional assets. In this approach, fracture modeling and advanced rate-transient techniques are used to constrain fracture geometry and depletion characteristics of existing wells. This knowledge is used in finite-element geomechanical modeling to predict fracture orientation in nearby wells. In this paper, an integrated methodology is described and applied to a shale-gas pad as a case study.

Introduction

Although it is generally accepted that geomechanical stresses are important for understanding fracture propagation in shales with low contrast in principal compressive stresses, the absence of precise knowledge of input parameters needed for reliable predictions has limited the broad use and applicability of geomechanical models. Parameters such as permeability, fracture half-length, number of propagated fractures, and geological heterogeneity still carry much uncertainty for shales and can have a significant effect on model predictions. A methodology is presented to address some of these limitations by integrating knowledge derived from production and fracturing data to reduce the uncertainty in key parameters and enable realistic predictions (Fig. 1).

The spatial and temporal evolution of stresses for multiple horizontal fractured shale-gas wells on a pad has been investigated by explicitly modeling each of the hydraulic fractures extending from the wellbore. The models are constructed by use of simplifying assumptions of planar biwing fractures. Both 2D plane-strain and full 3D formulations are used. The results reveal significant reorientation of principal stresses thousands of feet away from a producing well in addition to the anticipated near-fracture stress changes. The reorientation of stresses far from a producing well can have a significant effect on hydraulic-fracture propagation during stimulation of new infill or neighboring wells.

Methodology

A multidisciplinary approach integrating aspects related to completion, reservoir production, and geomechanics was used to optimize development of unconventional gas assets.
En Route: Why Peer Review?
Authors: Labastie Alain
Published: February 2015

President's column

“Peer review” is a term that is not always fully understood, so let’s talk about peer review and related issues for SPE.

Papers presented at SPE conferences are selected on the basis of an abstract (roughly 300 words) submitted by the author. The meeting program committees are selecting abstracts that presumably will be transformed into good papers. A “good paper” is one that addresses a relevant topic, with adequate technical content. Although this selection process provides a screening, and many of these papers are quite interesting, they have not been peer reviewed.

After he/she sends the manuscript for inclusion in the meeting’s proceedings, the author may choose to also submit his/her paper for publication in one of SPE’s seven peer-reviewed periodicals. Peer review is the process by which those papers are evaluated. For SPE, this means that the paper will be critiqued by two or more industry or scientific experts (the peers), who will consider such questions as

Is the problem well defined, and is it a real one?

Is the problem solved in a sound way?

Do the conclusions make sense?

In case of a field case description, are there enough data to understand and from which to learn?

Sometimes, in a technical or scientific demonstration, the author has to make choices. The author should clearly explain those choices, and the reviewer should not criticize those choices even if they are different from his/her personal views, provided they are technically sound. The reviewers often specify improvements (minor or major) to be made to the paper before it can be published in a journal, and sometimes more than one round of review and revision are necessary before the paper is accepted.

So the answer to the question “why peer review?” is clear: the process provides a good guarantee of quality for the papers published. In the scientific domain, peer review has proven to be a very efficient and successful tool for the progress of science in general. I believe that the same is true in the domain of engineering. And papers that are peer approved, like those published in SPE journals, offer a much higher guarantee of quality as compared to papers available in commercial publications, which are published without such rigorous evaluation.

Peer review is also very important for the academic world; for a career in academia, it is necessary to regularly have papers published in a peer-reviewed journal. It is right for SPE to offer a home for the petroleum engineering domain.
Gorgon To Drive Australian LNG Asia-Export Surge
Authors: Parshall Joel
Published: February 2015

Gorgon project

One of the world’s largest natural-gas projects, involving one of the largest, most advanced carbon-dioxide-sequestration initiatives, is moving ahead in Coastal Western Australia. The Chevron-operated Gorgon project will develop offshore reservoirs for liquefied-natural-gas (LNG) export and domestic gas-market supply, centered around LNG and gas-plant facilities to be built on Barrow Island. Sanctioned in 2009, Gorgon is in its construction phase and is slated to begin operations in 2014.

Not far behind is another huge Chevron-led natural-gas/LNG project, Wheatstone, in which company and third-party fields off Western Australia will be developed and tied into a planned coastal LNG-export and domestic-gas processing hub. Front-end engineering and design are under way, with a final investment decision expected in 2011.

LNG exports to Asia Pacific customers are at the heart of both projects, which together point to a surging importance of Australian LNG in the world market. Australia is the world’s sixth largest exporter of LNG, and some market observers believe that anticipated projects could elevate Australia to No. 1 in world LNG exports within about a decade.

‘An Energy Sweet Spot’

“In every sense, the biggest game in town is the development of megaprojects for the export of LNG,” Western Australia Premier Colin Barnett said earlier this year.

In a recent talk to the Australian Petroleum Production & Exploration Association, Roy Krzywosinski, managing director, Chevron Australia, said, “Our industry finds itself in an energy sweet spot, surrounded by natural-gas resources on the doorstep of the world’s biggest and fastest-growing market, the Asia Pacific region.”

Gorgon’s reserves lie within the Greater-Gorgon-Area gas fields in the Carnarvon basin off the northwest coast of Western Australia. The initial phase of development includes 18 subsea wells to be drilled in two separate fields: Gorgon, approximately 80 miles offshore in 660 ft of water; and Jansz-Io, approximately 125 miles offshore in 4,300 ft of water. It is anticipated that up to 30 wells will be drilled in the Gorgon-area fields over approximately 30 years.

From the wellheads, gas will flow to one of several cluster manifolds to be installed nearby on the seafloor, at which production from multiple wells will be combined and routed in a single flow path from each manifold to pipeline-termination structures. A system of flowlines will connect these termination points with each other. Produced gas will flow through lines leading from the termination structures and eventually traveling up a steep, 5/8-mile-high underwater escarpment en route to the Barrow Island processing facilities.

All subsea equipment will be monitored and controlled from the onshore LNG plant by means of an electrohydraulic multiplexed system with primary fiber-optic communications, which will incorporate a system of subsea control umbilicals to tie in the seafloor infrastructure with the plant.
Technology Focus: Drilling and Completion Fluids (November 2010)
Authors: Estes Brent
Published: February 2015

Technology Focus

Last year, I wrote about the science-based approach to fluids and the increased level of knowledge required of drilling-fluids-related professionals. This year, I want to emphasize the importance of drilling and completion fluids in well control, lost-circulation mitigation, and wellbore stability.

One of the first things you learn as a drilling engineer or rig supervisor is that the most important aspect in drilling is the drilling fluid (this may be a little biased coming from a fluids specialist). It is like the blood in our circulatory system! It serves many functions and can be either friend or foe, depending upon how it is maintained.

The primary function of drilling or completion fluids is to control subsurface pressures. With the challenge of drilling in ever-increasing water depths and into higher-pressure and temperature reservoirs in the pursuit of hydrocarbons, this becomes even more important and more difficult to accomplish. Additionally, the fluid density required to control formation pressures often is very close to the fracture gradient, so that there is a delicate balance between well control and lost returns. Another issue to consider is the effect that fluids have on wellbore stability. With the increased complexity of the wells being drilled, higher fluid densities are needed to prevent the hole from becoming mechanically unstable, thus narrowing the “safe drilling window” between borehole stability and lost returns. Various techniques are used to address this issue. Factors such as formation type and characteristics, type of loss, and others should be considered when selecting the most appropriate solution. There is no “one size fits all” approach that works.

The papers in this feature address issues in the preceding discussion. Please take time to read them along with the papers listed for additional reading.

Drilling and Completion Fluids additional reading available at OnePetro: www.onepetro.org

SPE 130413 • “Vital Role of Nanopolymers in Drilling- and Stimulation-Fluid Applications” by Subodh Singh, University of Oklahoma, et al.

SPE 125708 • “Remote Real-Time Monitoring of Particle-Size Distribution in Drilling Fluids During Drilling of a Depleted HP/HT Reservoir” by Egil Ronaes, SPE, M-I Swaco, et al.

SPE 130421 • “Utility-Calculation Method of New Four-Parameter Rheological Model for Drilling Hydraulics” by Guo Wang, China University of Petroleum, Beijing, et al.

SPE 128405 • “Salinity-Based Pump-and-Dump Strategy for Drilling Salt With Supersaturated Fluids” by T.J. Akers, SPE, ExxonMobil
An Engineered-Particle Drilling Fluid To Overcome Coal Drilling Challenges
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 128712, ’Utilizing an Engineered Particle Drilling Fluid To Overcome Coal Drilling Challenges,’ by Sabine Zeilinger, SPE, and Fred Dupriest, SPE, ExxonMobil Development Company; Ryan Turton, SPE, Esso Australia Pty. Ltd.; and Hayden Butler, SPE, and Hong Wang, SPE, Halliburton, originally prepared for the 2010 SPE Drilling Conference and Exhibition, New Orleans, 2-4 February. The paper has not been peer reviewed.

Borehole instability and stuck pipe while drilling coal can lead to significant nonproductive time.  The full-length paper describes a drilling fluid developed to stabilize coals in a program that previously was unable to achieve all extended-reach objectives. The fluid-design principles are believed to apply broadly in stabilizing coals, fractured shale, and other cleated formations.

Coal Cleats

One of the main characteristics of coal is a system of cleats, regular gaps and fractures in the coal that vary with coal maturity (Fig. 1). The fractures occur most commonly perpendicular to each other, and typically perpendicular to the bedding plane. Modeling suggests that under pressure, coal cleats may be 3 to 40 µm wide. These cleats form an interconnected network of fractures that contributes to methane production. In the case of coalbed methane, some methane adsorbed on the surfaces of the cleats may contribute to the total methane production. Drilling-fluid invasion while drilling can lead to significant formation and production damage. Concepts that have been developed for stabilization of uniform, low-permeability shales may not yield the expected results because of the unique physical characteristics of coals, particularly the existence of a cleat system.

Borehole-Instability Mechanisms

When a hole is drilled, the borehole wall must carry the load that previously was supported by the removed rock. This causes the hole to attempt to contract in the radial direction, leading to a stress concentration in the immediate vicinity of the wellbore: the tangential, or hoop, stress. If the resulting effective stress in the near-wellbore region exceeds the strength of the rock, the formation fails. Drilling-fluid pressure resists the effective stress, which limits the strain and stress that can develop in the tangential direction. Fluid density has to be increased to a level that reduces the effective stress to less than the strength of the rock. A sufficiently high mud weight can alleviate the stress concentration around the wellbore and provide sufficient support on the wall. The basic failure concept is no different in coals than in shales and other formations.