bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil Shale: The Rock That Burns
Authors: Beckwith Robin
Published: February 2015

The term “oil shale” refers generally to fine-grained sedimentary rock that contains solid bituminous materials, called kerogen, which can be converted into liquid and gaseous hydrocarbons (petroleum liquids, natural gas liquids, and methane) when the rock is heated in the chemical process of destructive distillation known as pyrolysis. Oil shale is found in a variety of depositional environments, including fresh water to highly saline lakes, epicontinental marine basins and subtidal shelves, and in limnic and coastal swamps, commonly in association with deposits of coal. Unlike crude oil or even tar sands, oil shale has not been subject to high enough heat over a long enough period of time to break the complex solid hydrocarbons down into lighter, liquid and gaseous compounds. One of its defining characteristics, however, is that it contains enough oil to burn without further processing, giving rise to its Ute Indian name, “the rock that burns.”

According to Jeremy Boak, director of the Center for Oil Shale Technology and Research, “oil shale” is not a misnomer, as is commonly held. “If oil shale is not shale,” he said, “then neither is the Barnett, the Haynesville, the Niobrara, or the Eagle Ford.” The difference is that shale oil, as currently used for plays like the Bakken and Eagle Ford, refers to rock that contains liquid hydrocarbons, and oil shale refers to rock that yields hydrocarbons upon heating under appropriate conditions. Many names have been used for oil shale over the centuries, such as albertite, algal coal, alum shale, bituminite, boghead coal, cannel coal, gas coal, kerosene shale, kukersite, schistes bitumineux, stellarite, tasmanite, torbanite, and wollongongite. Some of these names are still in use.

The organic matter in oil shale—composed chiefly of carbon, hydrogen, oxygen, and small amounts of sufur and nitrogen—is predominantly kerogen, which by definition is an organic material that is typically insoluble in ordinary organic solvents. The mineral and elemental content of oil shale differs distinctly from coal. The ash (or mineral) content of coal is generally less than 40 weight percent (wt%), whereas oil shale commonly has an ash content greater than 60 wt%. The organic matter of oil shale typically has a higher hydrogen and lower oxygen content than that of lignite and bituminous coal.
Technology Focus: CO2 Applications (July 2011)
Authors: Rogers John D.
Published: February 2015

Technology Focus

The CO2 supply-and-demand trends for enhanced-oil-recovery (EOR) projects are diverging, and many EOR projects, especially in the US, are hindered by lack of sufficient economic CO2 volume and infrastructure. The CO2-supply deficiency—and because a portion of the estimated 30+ Gt/year of anthropogenic CO2 worldwide could supply future EOR projects sufficiently—is driving the EOR industry to be an enabler for early carbon-capture-and-storage (CCS)/sequestration technology and infrastructure development. As EOR/CCS develops, the potentially huge, yet unproven, storage capacity of deep saline formations may become more realistic. The methodology of how to quantify and use saline aquifers is in the developing stages with technical debates.

Geotechnical and transportation issues for CCS are similar to those for EOR processes, but there are differences because of their different purposes. EOR projects have fairly short-term time scales, of several 10s of years after initiation of EOR processes. CCS projects have similar 10s of years of injection time, but indefinite time scales (1,000s of years) for the mineralization processes to be effective. Geological and mineralogical models; coupled geochemistry, geomechanical, and transport models; seal-integrity issues typical of hydrocarbon-phase-behavior physics; large time-scale differences; subsurface uncertainties; and limited or no performance data complicate optimization of CO2-capacity determination and efforts to model the CCS process(es) and sites compared with modeling typical or even atypical EOR projects.

Except for natural-gas plants, business models of large stationary facilities generally view CO2 as a waste. To an operator, CO2 is an expensive but useful fluid to enhance hydrocarbon recovery. In May 2010, the US Environmental Protection Agency issued its final rule addressing greenhouse-gas emissions from large stationary sources and defined CO2 as a pollutant at certain high concentrations, not as a waste. Future business venues for EOR/CCS most likely will include partnerships and alliances with power plants and other large stationary generators to provide and economically capture, use, and store CO2, thus creating a limited CCS industry enabled by the EOR industry.

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

SPE 139588 • “The Significance of Caprock-Sealing Integrity for CO2 Storage” by A. Busch, Shell, et al.

SPE 134028 • “Drainage and Imbibition CO2/Brine Relative Permeability Curves at Reservoir Conditions for Carbonate Formations” by D. Brant Bennion, SPE, Weatherford, et al.

SPE 131609 • “Static and Dynamic Estimates of CO2-Storage Capacity in Two Saline Formations in the UK” by Min Jin, SPE, Heriot-Watt University, et al.

SPE 139716 • “Perspectives on CCS Cost and Economics” by H.S. Kheshgi, SPE, ExxonMobil, et al.
Spectrum: Building Our Future
Authors: Thakur Ganesh
Published: February 2015

President's column

The future of our industry is challenging; it is geologically challenging, technologically challenging, and financially challenging, and it is resource intensive. Reservoirs are increasingly difficult and costly to develop and oil and gas comes at a higher cost of extraction. A host of other possible roadblocks complicate this future, including public concern about water issues; environmental impact assessments perhaps limiting access to resource; growth in regulations; and longer permitting processes. This is not an easy scenario.

To achieve the production demands of the future, a significant increase in global energy-related investment will be needed over the next 20 years, especially in technology development. But I believe an even larger piece of global oil and gas investment needs to be in people.

Although the economic downturn has delayed retirements, many engineers and geoscientists working in our industry will retire in the next 5 to 10 years. With the experienced professionals leaving the workforce, our young professionals (YPs) are being asked to take on more responsibilities earlier in their careers. This means that YPs must acquire broad technical and soft skill sets to be able to perform the complex tasks required of them. This requisite, coupled with the increasing complexity of the E&P environment, compounds the challenges facing the industry.

To attract and retain the kind of world-class technical expertise we need to succeed today and tomorrow, we must be willing to invest in extensive training programs that focus not only on the hard technical skills, but also on soft skills such as teamwork and interpersonal communication. This approach will enable YPs to give our industry their best in the fast-moving, team-driven workplace that technology solutions increasingly require.

So how do we attract the talent and accelerate their development? The answer is fundamental to SPE’s purpose: through the power of information dissemination and collaboration.

Sharing knowledge and best practices are essential to help accelerate the time it takes for YPs to reach their full productivity. This is a subject that SPE, especially the board of directors, is very passionate about. SPE has many resources that promote the YPs’ ability to learn from both experienced professionals and each other, and to build valuable networks that will serve them well throughout their professional life, resulting in a stronger industry as a whole.
A Roadmap for Addressing Environmental and Social Issues Associated With Horizontal Drilling and Hydraulic Fracturing
Authors: Liroff Richard A.
Published: February 2015

R&D Grand Challenges - This is the latest in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT).

The energy industry faces a massive communications challenge in persuading sizeable sections of the public in the United States and overseas that natural gas operations relying on horizontal drilling and hydraulic fracturing can be conducted safely. Mitchell Energy founder George Mitchell has stated that industry has “the duty to fracture responsibly.” He was candid when he said, “There is no question that accidents have occurred and mistakes have been made during the rush to develop.”

Mitchell’s candor was remarkable because, for too many years, the industry has mainly responded to attacks on shale gas operations by pointing out errors or omissions in critical media accounts. The industry has also emphasized the 60-year history of hydraulic fracturing while ignoring the growth of legitimate public concerns arising from the exponential growth of combined horizontal drilling and hydraulic fracturing during the past 15 years. Thoughtful companies recognize that this has not been a successful strategy for building public trust, and they are beginning to speak directly to the real risks associated with their operations. These real risks include, for example, poor cementing practices in well construction and inadequate waste-water management.

Since mid-2009, investors have been seeking increased disclosure by companies of the environmental and social risks associated with natural gas operations in shale formations and the policies and procedures they are adopting to reduce or eliminate these risks. Risks are associated with the broad life cycle of shale gas operations, not just with hydraulic fracturing as technically defined. Fracturing and horizontal drilling together make substantial recovery of gas from shales economically possible and have brought drilling and production to localities on a scale previously not experienced.
Industry Focuses on Operational Integrity, Safety Issues at OTC
Authors: JPT staff _
Published: February 2015

Conference review

Improving offshore safety and operational integrity through both technology and processes weaved its way through many of the panel and technical sessions at this year’s Offshore Technology Conference, held in May in Houston.

The annual conference continues to grow; this year’s attendance reached a 30-year high of 89,000, and the exhibition was the largest in the event’s history. “OTC 2012 was the most successful event we have had since the early 1980s,” said Steve Balint, chairman of OTC. “In terms of strength of the technical sessions and technology on display, OTC reached a record-breaking number of people and offered the most ways to connect, educate, and conduct business. The industry is on the rise and challenges are ahead, making it more important than ever to collaborate and share best practices with colleagues all over the world.”

Two years after the Macondo accident in the US Gulf of Mexico, the impact of that disaster is still being felt as the industry grapples with new regulations and works to create new technology that will make operations safer and efficient. These issues dominated many sessions and discussions during the 4-day conference.

Examining Operational Integrity

In one panel session, representatives from an industry safety body, a risk consultancy group, and the regulatory sphere spoke about improving operational integrity in the offshore energy sector. Francesca Rinaldi, production optimization manager at Eni, said that the safety of people and protection of the environment are the foundations of well-integrity objectives and that organization, processes, and technology are the pillars of well-integrity management. Her company has created a software package that it calls a well-integrity tool, which takes critical well data from operations, enables analysis by company personnel, and indicates whether a well is in compliance with requirements established for the operation. “Safety and performance go hand in hand,” Rinaldi said.

Robert Patterson, Shell’s vice president of upstream projects in the Americas, discussed operational integrity from a project perspective. He cited the execution of Shell’s Perdido spar project in the deepwater Gulf of Mexico, in which project personnel worked from start to finish without a single person losing a workday because of a safety incident. Two key factors in achieving that record, Patterson said, were “extreme, visible, passionate commitment from leaders in the project” and “partnerships across companies, with regulators, with stakeholders, with suppliers, with operators.” Shell’s upstream sector views asset integrity and process safety as a function of design integrity, technical integrity throughout an asset life cycle, and operating integrity, he said. Patterson also stressed the need for the industry to move from a task-driven approach to a purpose-driven approach to work throughout the supply chain.
Technology Focus: Reservoir Simulation (July 2012)
Authors: Crick Martin
Published: February 2015

Technology Focus

This year, there were approximately 200 papers on simulation to select from—and that is after a separate feature on history matching. So, the discipline continues to be active. A noticeable feature is the growing number of simulation papers that use different technology, in the broadest sense of the term—for example, using concepts from signal processing and electrical engineering to model subsurface flow or related phenomena. However, the dominant technology remains finite different representations of Darcy’s law, conservation of mass, and a fluid model.

What is also heartening is the fact that all significant papers on case studies start with descriptions of the geology and often include detailed description of 3D geological modeling. Any simulation that is based on a physical model of the field must surely depend on the quality of the geological model used as input; yet, not that long ago, it was normal to pay only scant regard to the geology when constructing a model and even less when altering it during history matching.

Recent discussion within the SPE Simulation Technical Interest Group has raised the issue of pseudorelative permeabilities, with some arguing that they are obsolete and others strongly disputing the claim. Sadly, there were no papers on the subject that I could include in this feature. The relative permeability curve is where engineering meets geology; anyone involved in complex projects—and who of us is not—knows that it is at the interfaces that complexities arise and are too often ignored. The same is true in our models, so surely relative permeabilities and their multiphase upscaling are topics worth renewed investigation.

All three of the case studies I have selected, which are all from very different settings and parts of the world, were studies directed toward making tangible decisions (e.g., selecting well locations and completion intervals). This highlights once again that good simulation studies are directed toward decision making; having a clear sight of the purpose of the work improves the quality of the work and, thus, of the ultimate decision. The converse is also true.

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

SPE 146366 A Capacitance-Resistive Model and InSAR Imagery of Surface Subsidence Explain Performance of a Waterflood Project at Lost Hills by Wenli Wang, The University of Texas at Austin, et al.

SPE 146524 Reservoir Simulation: A Reliable Technology? by W.J. Lee, Texas A&M University, et al.

SPE 146574 Impacts of the Porosity/Permeability Transform Throughout the Reservoir-Modeling Workflow by R.D. Roadifer, ConocoPhillips Alaska, et al.
High-Resolution Reservoir Simulation Constrained to Complex Clastic Rock Bodies
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148331, ’A High-Resolution Reservoir-Simulation Model Constrained to Complex Clastic Rock Bodies for a Realistic Study of an Offshore Field,’ by Ahmad J. Sultan, J.A. Vargas-Guzman, and Jamil S. Thuwaini, SPE, Saudi Aramco, and Pranay Kumar, Beicip-IFP, prepared for the 2011 SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, UAE, 9-11 October. The paper has not been peer reviewed.

An unconventional state-of-the-art reservoir-simulation study was performed for an offshore field in the Arabian Gulf. The conventional history-matched model was valid at wellbores; however, clastic reservoirs usually present challenges for infill-drilling prediction at interwell locations because of complex geometries of curvilinear sandstone bodies. A rock-body-based simulation model was used for history matching and was investigated for further production-development scenarios.

Introduction

Highly heterogeneous clastic reservoirs present challenges to history matching; however, generating realistic models of clastic reservoirs enables optimum planning of development. The ultimate goal of this study was to create a realistic model for further testing of reservoir-development strategies for maximum-reservoir-contact (MRC) wells for development and optimization. An offshore field having complex sandstone bodies was selected. The main reservoir has stacked braided channels that form a main sandstone reservoir with very highly permeable rocks. Those formations are overlain and underlain with more-heterogeneous stringer sands surrounded laterally by shaly rock. The upper stringers contain significant undeveloped remaining reserves, which are the target for future development to extend the field’s oil-production water flow has been observed because of sandstone bodies connected to the aquifer.

A more-realistic model was required to investigate the development scenarios for this reservoir: drilling new wells targeting braided and distributary tidal channels with sandstone bodies in the tidal-dominated environment of the upper stringers. The earlier geological model was based on sequential-indicator simulation (SIS), which yielded optimistic forecast results. The major limitations of this type of model were that it did not account for the complex curvilinear geometries of sandstone bodies and did not capture the complex higher-order permeability distribution. The new rock-body-based geological model captures more-realistic geological features and should provide a better forecast representation of the reservoir by allowing testing of realistic orientation and completion of offshore wells drilled from platforms.
Technology Focus: Artificial Lift (July 2012)
Authors: Noonan Shauna
Published: February 2015

Technology Focus

Calling all technology champions! A few years ago, I ran across the seven steps to stagnation, which was a list originally compiled by Erwin M. Soukup. I got a feeling of déjavu reading through this list because I had heard these same words spoken from many managers and peers over my career. If you search for these seven steps on the Inter-net, you will find different variations; however, the message is the same. The seven steps are

We have never done it that way.

We are not ready for that yet.

We are doing all right without it.

We tried it once, and it did not work out.

It costs too much.

That is not our responsibility.

It will not work.

Great ideas for technology improvement or development can have an early demise when faced with feedback similar to what is on this list. Even with a patent, a product may never be commercialized without someone to be its champion. While we are fortunate to have many technology champions in the area of artificial lift, we need more.

The best way to meet and learn from our industry’s best artificial-lift champions is by attending some of the artificial-lift forums, workshops, and conferences coming up in 2012 and 2013. Please check out the global events calendar on www.spe.org. One major SPE artificial-lift event you will not see on the global calendar, however, is the 2013 Electric Submersible Pump (ESP) Workshop. This is still a section-sponsored event; however, it has grown to be the primary conference for the ESP industry (the most-recent event had 560 attendees from 24 countries). Please go to this address for more information: www.spegcs.org/en/committees/display.asp?committeeid=5.

The first paper highlighted features the use of a downhole linear motor to drive a reciprocating-pump system. This is a new technology that is also featured in two papers to be presented at the 2012 Annual Technical Conference and Exhibition in San Antonio, Texas, this October. The two other highlighted papers focus on offshore artificial-lift systems and discuss the unique challenges and concepts being applied.

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

OTC 23079 - Mobile Gas Lift Compressor and Well-Unloading System for Enhancing Oil Production and Reserves, While Reducing Greenhouse-Gas Emissions in Offshore Environments by Jarrad Rexilius, Chevron, et al.

OTC 22579 - ESP-Assisted-Production Allocation in Peregrino Field by H. Olsen, Statoil Brazil, et al.

SPE 152229 - Calculation of Gearbox Torques of Rotaflex Pumping Units Considering the Elasticity of the Load Belt by G. Takacs, University of Miskolc, et al.
Program Considers What Is Needed for the Future of Carbon Sequestration
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper CMTC 151471, ’What's Next in Geologic Storage Research?’ by J. Litynski and T. Rodosta, US Department of Energy, National Energy Technology Laboratory; and L. Myer, R. Kane, and G. Washington, Leonardo Technologies, prepared for the 2012 Carbon Management Technology Conference, Orlando, Florida, 7-9 February. The paper has not been peer reviewed.

The US Department of Energy (DOE) launched its carbon capture and storage (CCS) program in 1997 after holding a stakeholders workshop to obtain feedback from the technical and commercial sectors on its draft research plan. Consistent with administration and congressional priorities, CCS continues to be a key element of the DOE’s research and development (R&D) portfolio. Implemented by the National Energy Technology Laboratory (NETL) within DOE’s Office of Fossil Energy, the program is playing a lead role in CCS technology development and has made significant advances in the development of a broad range of effective and economically viable technologies.

Overall CCS Program Goals and Objectives

The overall objective of the carbon-storage program is to develop and advance CCS technologies that will be ready for widespread commercial deployment by 2020. To accomplish widespread deployment, three program goals have been established: (1) develop technologies that will support industries’ ability to predict CO2-storage capacity in geologic formations to ±30% by 2015; (2) develop technologies to demonstrate that 99% of injected CO2 remains in the injection zones by 2015; and (3) complete best-practices manuals for site selection, characterization, site operations, and closure practices by 2020. Only by accomplishing these goals will CCS technologies be ready for safe, effective commercial deployment beginning in 2020 and through the next several decades.

CCS-Program Structure

The carbon-storage program is composed of three principal elements: core R&D, infrastructure, and global collaborations. It is the integration of these elements that addresses technological and marketplace challenges.

Core R&D. The core-R&D element involves applied laboratory- and pilot-scale research focused on developing new technologies and systems for greenhouse-gas mitigation. Core R&D encompasses four technical focus areas for CCS technology and protocol development:

Geologic storage

Monitoring, verification, and accounting (MVA)

Simulation and risk assessment

CO2 use

Infrastructure. The infrastructure element involves confirmation of CO2-storage approaches through activities such as the seven regional carbon-sequestration partnerships (RCSPs), which are conducting field tests, engaging regional stakeholders, and characterizing opportunities for CO2 storage in their regions. Nineteen small-scale and eight large-scale field projects were implemented by the RCSPs, and these involved site selection, CO2 injection into different geologic storage formation classes, monitoring, public outreach, and regulatory compliance.
Innovation: Innovations in Subsea Completions
Authors: Imomoh Egbert
Published: February 2015

President's column

The demand for more and more oil and gas has prompted the industry to seek new areas of hydrocarbon deposits, and the development of subsea completions has kept pace.  Many huge innovations have taken place since the first underwater completion was made about 70 years ago, when the first wet wellhead, basically a land Christmas tree, was deployed in shallow water. Finding hydrocarbons in deeper and deeper waters, away from existing infrastructure, has prompted the need to complete wells on the sea floor and then pipe production to floating facilities. The depth of water in which these wells were drilled made the use of platforms become technically unfeasible or not supportable by the economics of the development. The North Sea, Gulf of Mexico, Brazil, and west Africa have been the major areas of subsea development and reserves in increasing water depths have been brought into production, and more recent finds in east Africa are yet to be developed.

New technology has been deployed in a number of areas (Vernotzy 2013):

Drilling rig and equipment design capable of operating in water depths in excess of 3000 m

Better understanding of weather, ocean, and seabed conditions

Flowline and pipeline design and deployment

Design of very reliable processing and control systems

The development of sophisticated remotely operated vehicles (ROV)

A recent study (Nelson et al. 2013) to review and understand where oil and gas has been found recently revealed the following.

Globally, deep water has become a significant source of discoveries, accounting for more than 50% of new conventional reserves.

The size of deepwater discoveries is an order of magnitude larger than other discoveries.

However, less than 40% of those discoveries are in production, contributing less than 10% of conventional production.

Deepwater production could double in the next 7 years as more fields are brought into production.

Early deepwater development required the use of proven technology, innovation, commitment, and teamwork between license holders, equipment suppliers, and service providers. Given the depth, it was essential that equipment be designed to operate at a very high level of success.

Over the years, subsea completions have become more complex, varying from single wells connected to a platform to subsea “factories” consisting of an array of wellheads, manifolds, and processing equipment. Irrespective of the complexity of seabed configurations, the fluids produced will have to be channelled to an onshore handling facility or to a fixed or floating processing unit. Given the environment under which the installed equipment has to operate for long periods of time with minimum intervention, the equipment must be robust and reliable and must ensure safety for personnel and protection of the environment.
Molecular Simulation Helps Determine Key Shale-Gas Parameters
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164790, ’Molecular Simulation To Determine Key Shale-Gas Parameters and Their Use in a Commercial Simulator for Production Forecasting,’ by F. Gouth, Total; J. Collell and G. Galliero, Universite de Pau and Pays de l'Adour; and J. Wang, ecole Centrale de Pekin, prepared for the 2013 SPE Europec/EAGE Annual Conference and Exhibition, London, 10-13 June. The paper has not been peer reviewed.

Shale gas is fast becoming a source of energy of paramount significance for the coming years. Although commercial production has been achieved in numerous plays throughout the world, the actual physics involved is poorly understood. Molecular simulation is an emerging technique that can be put to use for shale gas. It offers insights into nanoscale properties such as sorption or transport coefficients. The technique is based on numerical simulations at the molecular scale for a given set of pressure and temperature conditions.

Introduction

Comprehensive organic-shale rock characterization performed in recent years has emphasized the dual nature of the porous system, which is split between organic and inorganic pores, each system having its own scales and associated physical properties. At least two clearly identified mechanisms are likely to cause composition changes over time: In tiny pores, where specific surfaces are huge with respect to volumes, gas exists in both free and condensed (adsorbed) states and in different compositions. Because free and adsorbed gas will not be produced at the same time in a well’s life because the process is pressure dependent, a change in the produced-gas-composition stream is likely. In addition, flow through the nanometer-scale pore system exhibits not a Darcy pattern but a diffusion type of flow (transitional or free molecular flow) where transport coefficients depend on the molecule size. This mechanism is well-known in gas chromatography as molecular sieving and also will result in composition changes.

This paper seeks to offer a comprehensive screening of the current means available for representing such effects and to examine their consequence on long-term production with an appropriate model.
Technique Uses Multilateral, Multisegment Wells To Represent Hydraulic Fractures
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163644, ’Representing Hydraulic Fractures by Use of a Multilateral, Multisegment Well in Simulation Models,’ by D.A. Edwards, SPE, Schlumberger; N. Cheng, SPE, Statoil; T.P. Dombrowsky (now with Longhorn Technologies) and G. Bowen, SPE, Schlumberger; and H. Nasvik, SPE, Statoil, prepared for the 2013 SPE Reservoir Simulation Symposium, The Woodlands, Texas, USA, 18-20 February. The paper has not been peer reviewed.

Simulating fractured wells is challenging and impractical with local grid refinement (LGR) in full-field models with a large number of wells each with multiple fractures. This paper describes a modeling technique by which hydraulic fractures are represented as part of the well model rather than as any form of refinement in the simulation grid. In this approach, a planar fracture is modeled by the mesh formed from the interconnected branches of a multilateral, multisegment well (MSW).

Introduction

Hydraulic fracturing can dramatically change the flow dynamics of a reservoir, so its correct modeling in reservoir simulation can be critical. However, the presence of hydraulic fractures presents a challenge in flow simulation. This is because these fractures introduce effects that operate on different length and time scales than do usual reservoir dynamics.

To overcome this problem, a multitude of modeling techniques and workarounds has been developed. These include the use of dual-porosity models, enhancement of the productivity index of the fractured wells, virtual well perforations to simulate the fractures, and explicit fine-scale gridding.

In full-field simulations, where an entire reservoir with complex geometry, multiple wells, and possible faults is modeled, LGR is a popular method representing hydraulic fractures. However, this approach introduces its own set of problems. For example, in structured grids, the overall orientation of the grid may not easily accommodate fractures, particularly if they are at arbitrary angles.

This paper investigates the modeling of hydraulic fractures as part of the well model. MSWs are a discretized model of a well where fluid flow inside the wellbore is computed by solving physical flow model equations in one dimension. This domain is made up of the segments of the well that consist of nodes, which are connected by pipes. MSWs allow for lateral branches off the main stem and for looped flow paths; both features are employed here for the modeling of hydraulic fractures.
Q&A with Luis Ramirez Corzo
Authors: Ramirez Corzo Luis , Donnelly John
Published: February 2015

Q&A - No abstract available.
Integrated Fractured-Reservoir Characterization and Simulation: Tunisian Application
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84455, "Integrated Fractured- Reservoir Characterization and Simulation: Application to Sidi El Kilani Field, Tunisia," by M. Laribi, ADCO; H. Boubaker, CTKP; B.J. Beck, KUFPEC; H.-K. Chen, SPE, Retired; K. Amiri- Garroussi, KUFPEC; S. Rassas, SPE, and A. Rourou, SPE, ADCO; T. Boufares, ETAP; H. Douik, AGIP; N. Saidi, ETAP; and A. Ouenes, EP Tech, prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
The Cement-to-Formation Interface in Zonal Isolation
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 88016, "The Cement-to-Formation Interface in Zonal Isolation," by H.K.J. Ladva, SPE, B. Craster, T.G.J. Jones, SPE, G. Goldsmith, and D. Scott, Schlumberger Cambridge Research, prepared for the 2004 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Kuala Lumpur, 13-15 September.

During the completion and production phases of the well, temperature and pressure variations can cause stresses at the cement-to-formation interface. The ability of the casing cement system to maintain a seal at the cement-to-formation interface depends on the condition of the formation surface before slurry placement. The condition of a shale will depend upon the nature of the drilling fluid used, whereas the condition of a permeable rock will depend upon the presence and nature of the filter cake deposited during drilling. The full-length paper presents an improved understanding of chemical interactions at the cement-to-formation interface and the factors that determine bond strength and the position of the plane of failure.

Introduction

Maintaining zonal isolation for the lifetime of oil and gas wells is critical. Leakage behind casing can reduce the cost-effectiveness of the well and cause health and safety risks from pressure buildup and contaminated aquifers. In the petroleum industry, many studies have been performed on the cement-to-casing interface and bulk cement to improve the isolation efficiency of the cement in the wellbore. Less attention has been given to the cement-to-formation interface. Ideally, samples of set cement and the adjacent formation should be recovered from oil wells to give a better understanding of the chemical nature of the interface under downhole conditions during the lifetime of the well.

Low-level radioactive waste sometimes is encased in cement blocks and lowered into clay beds. There is concern that, over time, alkaline fluids near the clay surface will alter its effectiveness as a barrier to the encased nuclear waste. Studies by the nuclear industry to increase their understanding of the cement-to-formation interface are ongoing.

At an underground laboratory in Belgium, plugs of cement were precured and then placed in cored-out holes in Boom clay. Samples were maintained between 65 and 85°C. After 12 to 18 months test time, the samples were cored out of the clay. Sections of the interface were analyzed by microprobe and X-ray diffraction. Observations from the study using ordinary Portland cement are summarized as follows.
Cementing a Long Horizontal Wellbore Using CT Squeeze Technology
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 94039, "Cementing a Long Horizontal Wellbore Using CT Squeeze Technology," by W. Rauchenstein and C.G. Blount, SPE, ConocoPhillips Alaska Inc., prepared for the 2005 SPE/ICoTA Coiled Tubing Conference and Exhibition, The Woodlands, Texas, 12-13 April.

Coiled-tubing (CT) cementing has been used widely and has been highly successful for remedial squeeze and plugback operations for more than 20 years. However, most of these wells had deviations less than 90°. A long horizontal well in the Alpine field on the North Slope of Alaska was drilled early in the development phase and was out of pattern. The well required a plugback and sidetracking to maintain desired off-take strategy. On the basis of the successful CT squeeze program in Alaska, the decision was made to use CT cement-squeeze technology to seal the lateral portion of the wellbore and leave a cement base for subsequent sidetracking operations.

Field Overview

The Alpine field is in the Colville River delta a few miles south of the Arctic Ocean and approximately 70 miles west of the TransAlaska Pipeline. The facilities are connected to the North Slope road system by ice road for approximately 3 months of the year. Aircraft provide the only mode of transportation at other times.

As a result of the depositional environment and minor fault offset, excellent vertical permeability is observed, and the productive sands are pressure connected across large distances. A water-alternating-miscible-gasflood is being conducted in the Alpine reservoir. The field is developed with line-drive patterns, using horizontal producers and injectors in a one-to-one ratio.

Given the high mechanical strength of the clean fine-grained Alpine sandstones, the operator elected to leave the horizontal sections of the wellbore uncased, to minimize the chance of formation damage. A 7-in. intermediate casing shoe is set just below the top of the producing formations at high angle. The uncased horizontal production hole typically extends 3,000 to 4,000 ft beyond the intermediate casing shoe. Production and injection tubing is primarily 4½ in., although some lower-rate wells are completed with 3½-in. tubing.

While performing above expectations, this completion practice has proved to be a difficult environment to access. Early attempts at logging these wells using CT memory tools and conductor-line tractors provided less than ideal results in reaching the total depth (TD) in the extended horizontal openhole sections. Drilling and formation debris and abrasive formations combined with wellbore geometry limited the ability to reach the full measured depth (MD) of the lateral sections. Portions of openhole lateral sections with fill or debris are not the only potential challenge to successfully cementing these wells; recent caliper logs suggest that the wells also may have sections that are washed out or significantly out of gauge.
Overview: Seismic Applications (August 2005)
Authors: Gibbons Kate
Published: February 2015

The age of digital technology has definitively arrived. As an industry, we now are reaping the benefits of many years of technology development as well as becoming mature in our ability to understand and evaluate the value of the data.

In reviewing papers from this past year, I noted several interesting case studies and methodologies for integrating seismically derived attributes with geological and engineering data to improve the characterization and management of fractured reservoirs. Nevertheless, I am primarily struck by the variety of papers related to the development and application of real-time data transmission from seismic while drilling, through crosswell seismic, to methods for acquisition at the seabed.

Much of the push has come from the exploration and development of deepwater reservoirs and the need for real-time integration of data to make well-informed decisions. Although driven by the high-end projects, the advantages of the technology are seen across the industry at large.

We are realizing the benefits of implementing digital technology in life-of-field studies, in the development of green fields, in intelligent drilling and completions, and in automation of decision support processes.

The “digital” toolbox is expanding. The expertise and domain knowledge required to further develop the technology extend across the entire range of classic sciences and will affect the way we work and communicate. Challenges still remain in our ability to integrate data fully and in how we use the information effectively. From the technical point of view, there still is work to do on fully integrated data-management platforms. On the human-resource side, we need great improvements in our ability to effectively manage communication across disciplines and to bridge the gap between onshore and offshore personnel.

The articles selected here represent a taste of the trends and developments in digital technology from drilling and completion, to seismic at the drill bit, to seabed- and marine-seismic acquisition, to life-of-field development scenarios.

Available from the SPE eLibrary: www.spe.org

SPE 89994 - “Seismic Pore-Pressure Imaging in Deep Water Offshore West Africa,” by Banik, N.C., SPE, WesternGeco, et al.

Available at the OTC Library: www.otcnet.org

OTC 17284 - “Remote Reservoir-Resistivity Mapping—Breakthrough Geophysics for the Upstream,” by Srnka, L.J., ExxonMobil Upstream Research Co., et al.

OTC 17669 - “Defining Fault-Exclusion Zones at Proposed Suction-Anchor Sites Using an AUV Micro-3D-Seismic Survey,” by Campbell, K.J., Fugro GeoServices Inc., et al.

OTC 17646 - “LWD for Imaging, Wellbore Placement, and Formation Evaluation,” by Rasmus, J.C., Schlumberger, et al.
Hydrocarbon Exploration Using Marine Electromagnetic Techniques
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17168, "Hydrocarbon Exploration Using Marine EM Techniques," by S. Constable, Scripps Inst. of Oceanography, U. of California San Diego, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May.

Recent interest in marine electromagnetic (EM) methods has been driven, in large part, by the challenges in deepwater exploration and associated efforts to reduce risk through the acquisition of additional data streams. The catalyst for the latest developments in marine EM technology was the problem of subsalt exploration in the Gulf of Mexico. Investigations were made of the use of controlled-source EM (CSEM) methods for direct hydrocarbon detection. Field trials were carried out offshore Angola.

Methodology

Fig. 1 shows the basic methods of marine EM studies. Seafloor recorders make time-series measurements of the electric and magnetic fields at discrete locations. The ionospheric and magnetospheric marine magnetotelluric (MT) source fields propagate into the sea, and a seafloor MT response can be processed from the data much like a land MT impedance, with two significant differences.

Attenuation in the conductive seawater layer dramatically reduces the electric- and magnetic-field energies at higher frequencies. Although MT responses on land can be processed routinely to several hundred hertz, in 1000 m of seawater it is essentially impossible to obtain MT data at frequencies higher than 1 Hz. Until the development of a broadband seafloor instrument, there were few attempts to collect seafloor MT data at frequencies greater than 0.01 Hz. Attenuation is less in shallower water (signal strength decreases with water depth squared), but the MT source fields decrease in magnitude with frequency, offsetting the shallow-water improvement.

The seafloor 1D MT response is the same as would be observed on land over the same geological structure without the ocean layer. However, the magnetic field is affected significantly by seabed conductivity, even in the 1D case (in stark contrast to land, where the magnetic field is essentially uniform, especially away from lateral contrasts in conductivity). A hybrid MT response obtained with the seafloor electric data and nearby land magnetics (equivalent to a sea-surface magnetic record) was used in the early development of the method to finesse the effects of motional noise in the seafloor magnetic data). This response illustrates the effect of seafloor conductivity on the magnetic field. In the case of 2D and 3D seafloor conductivity structure, a vertical electric field is possible in the seawater layer near the seafloor, although this effect is usually very small.
Discussion of SPE 89325, "Beyond Beta Factors: A Complete Model for Darcy, Forchheimer, and Trans-Forchheimer Flow in Porous Media"
Authors: van Batenburg Diederik , Milton-Tayler David
Published: February 2015

In SPE 89325, summarized in the March 2005 issue of JPT, Barree and Conway state that “new experimental data, under high-rate flow conditions, showed conclusively that Forchheimer’s equation, like Darcy’s law, has a limited range of applicability.” We agree with Barree and Conway that when flow tests have significant non-Darcy effects, interpretation is not always straightforward. However, we disagree with Barree and Conway that Forchheimer’s equation cannot be used to describe pressure-loss velocity dependency at high rates of practical relevance, and we would like to present data collected in two other laboratories to support our point of view.

At FracTech, high-rate gas-flow tests on proppant packs have been conducted since the early 1990s. The tests are typically conducted with nitrogen at ambient conditions to measure the flow rates accurately. Fig. D-1 shows a Forchheimer graph for 20/40-mesh sand at 2-lbm/ft2 concentration for values of ρv/µ up to 330. The data show a linear trend with a coefficient-of-determination value, R2, of 0.9991. This range for ρv/µ is double that in Fig. 2 of SPE 89325. These data were originally presented in SPE 90406. Fig. D-2 is another Forchheimer graph from SPE 90406. The data presented are for resin-coated lightweight proppant with a 16/20-mesh size distribution. Again, a linear relation with an R2 of 0.9998 is observed over the range of ρv/µ values from 10 to 320.

At Halliburton’s European Research Center (ERC), high-rate flow tests on proppant packs have been conducted with water as the flowing medium. Fig. D-3 shows the results of two such flow tests with 18/30-mesh high-strength proppant at 160°C and 10,000-psi stress. Again, the Forchheimer graphs show a linear trend (R2 of 0.99+) for each test over a similar range of ρv/µ values for which Barree and Conway claim nonlinear behavior.

Last, but not least, we would like to share a Forchheimer graph for a pack of 1-in.-long pins as shown in Fig. D-4. The Forchheimer plot, shown in Fig. D-5, again shows a linear behavior over the entire ρv/µ range evaluated. The shape of the particulate used appears not to affect the linear behavior.

The main difficulty in the use of the Forchheimer graph is illustrated by the two data sets presented in Fig. D-3: Although the slope of the lines is almost identical (meaning identical Beta factors), the intercepts with the y-axis that represent the inverse absolute permeability differ significantly. We conclude that, for practical purposes when non-Darcy effects are important, the Forchheimer equation and graph can be used.