bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovation: SPE Unveils a New Strategic Plan
Authors: Imomoh Egbert 
Published: February 2015

President's column
By all objective measures, SPE is a very successful organization. Our membership, which has become increasingly global, has more than doubled in the past decade. The number of conferences and workshops has increased without compromising on quality. We’ve added new offices to serve our global membership. And we’ve added numerous new programs and services. We have managed our resources prudently and are financially healthy (see my article in last month’s JPT). But an organization that doesn’t periodically examine where it is going, especially in light of very rapid changes in the external environment, won’t remain successful.
In June 2012, the Board of Directors initiated a process to develop a new strategic plan for SPE. We gathered input from industry leaders, the Board, SPE members, and staff through a survey and interviews. This input framed the discussion at a Board workshop prior to the Annual Technical Conference and Exhibition last October, where we explored additional initiatives and discussed priorities. During the workshop, the Board confirmed that SPE’s mission statement correctly defines what we’re about, and it crafted a revised vision statement:
Enable the global oil and gas E&P industry to share technical knowledge needed to meet the world’s energy needs in a safe and environmentally responsible manner.
As part of the strategic planning process, the Board also considered the most significant threats to SPE’s continued success. The first threat has to do with oil and gas price volatility, which could affect support for SPE activities including membership and attendance at events. While SPE cannot influence the price of oil or gas, we can ensure that we are sufficiently prepared to withstand the impact of a price decline by making prudent investments and managing our costs. The second threat relates to concern that the quality of programs could be impacted by a rapid growth in SPE programs. To sustain our success, SPE must ensure that technical quality is not compromised. The third issue has to do with the changing demographics of SPE’s membership. More members are coming from areas that do not have a strong tradition of volunteerism. Coupled with the pending retirement of many of SPE’s long-time active volunteers, this could pose a significant challenge to SPE’s traditional volunteer-driven path to programming that must be addressed.
In Search of the Waterless Fracture
Authors: Rassenfoss Stephen 
Published: February 2015

Waterless Fractures
The first hydraulic fracture experiment was waterless. A gasoline gel was injected into the Hugoton field in 1947. What was once an emerging technology in the US has become the growth engine for oil and gas production globally, and the napalm-based mix that was used then looks like an anachronism.
But fracturing using hydrocarbons is on the short list of options for the industry, which is looking for an effective substitute for water in hydraulic fracturing.
Environmental questions have arisen about water use and water quality in unconventional resource development, which requires millions of gallons of water per well to open path-ways for oil and gas trapped in nearly impermeable rock.
The Research Partnership to Secure Energy for America (RPSEA) has one waterless project in progress—to see if liquid nitrogen can fracture effectively—and the government/industry-funded research group is seeking more projects that experiment with waterless alternatives. “Water does work and has opened up the shale resources,” said Kent Perry, vice president of onshore programs at RPSEA. “(Fracturing) does take a lot of water. If you are in an area, particularly in parts of south Texas that are in a drought, even a little water is precious.”
Another driver for seeking waterless fractures is the search for a way to pro-duce more of the oil and gas out of the ground. Oil recovery in unconventional formations is generally well below that of conventional formations, with 3% to 6% estimated ultimate recovery rates in many unconventional oil formations.
“If you recover 10% (of the oil and gas), you are doing well but you are leaving 90% behind,” Perry said. “It is not just the fracture treatment. The whole approach will have to be looked at within those resources.”
Waterless fracturing could also remove an impediment to tapping unconventional formations in many spots around the world: limited water supplies. During a panel discussion at the recent International Petroleum Technology Conference, Peter Voser, chief executive officer of Shell Oil, said he “told the R&D group to come back with the waterless fracture.” His comment was delivered in Beijing, where Shell has been aggressively pursuing unconventional exploration opportunities in a country that has both enormous unconventional natural gas reserves and water shortages over large areas.
New Methods and Workflows Boost Effectiveness of Multizone Stimulation
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 16865, ’Improved Methods and Workflows for Multizone Stimulation,’ by Kris Nygaard, SPE, ExxonMobil Production; Shekhar Gosavi and Pavlin Entchev, SPE, ExxonMobil Development; and Fuping Zhou, SPE, Wadood El-Rabaa, SPE, and Chris Shuchart, SPE, ExxonMobil Upstream Research, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
Novel multizone stimulation technologies have enabled the development of tight resources that previously could not be developed economically and have enabled optimization of production resources distributed over thick gross intervals. These technologies are expected to become more broadly used for numerous applications worldwide because of their ability to rapidly place numerous stimulation treatments tailored to the specific needs of each zone, pump each treatment efficiently and effectively, and make more efficient use of equipment, people, and surface-site development.
Introduction
Unique stimulation challenges arise when hydrocarbon resources comprise multiple vertically distributed discrete reservoir intervals contained in long productive intervals or when targeting tight reservoirs with horizontal wells having extended lateral sections in reservoirs with significant heterogeneity. The overall challenge is characterized by the need to manage a balance between the number of stimulations performed, stimulation-treatment quality, cost, and the overall reliability of treatment placement and execution. Currently, managing this balance can result in operators intentionally bypassing less-attractive hydrocarbon intervals, incurring lower production because of poor stimulation effectiveness, labeling resources as uneconomic on the basis of the cost required to access the reserves, or having difficulty in achieving reliable and effective treatment placement. During the last decade, extensive research and field experimentation enabled the development of unique workflows, modeling capabilities, and stimulation methods for tight sandstone, shale, and carbonate formations.
Hydraulic-Fracture-Stimulation Design Methodology
The stimulation design methodology revolves around identification of the optimum completion scenario for the given reservoir conditions and local situation. Compared with conventional reservoirs, unconventional reservoirs with low matrix permeability, low porosity, and high water saturation may be more prone to damage and flow impairment.
Extensive field experience and measurements show the effective fracture volume is always less than the induced one. The rock is anisotropic and heterogeneous. In some cases, simple biwing-like fractures may be induced if the stress anisotropy is high; alternative fractures could be complex clusters with low anisotropic stress state. It is crucial to determine optimum completion scenarios, including horizontal longitudinal, horizontal transverse, or multizone vertical stimulations (Fig. 1).
Optimization of Limited-Entry Matrix Acid Stimulations in the Danish Central Graben
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 157429, ’Optimization of Limited-Entry Matrix Acid Stimulations With Laboratory Testing and Treatment Pressure Matching’ by Mary S. Van Domelen, SPE, and Mohamad abd Hammoud, Maersk Oil Denmark; Gerard Glasbergen, SPE, Shell; and Noor Talib, SPE, Maersk Oil Qatar, prepared for the 2012 SPE International Production and Operations Conference and Exhibition, Doha, Qatar, 14-16 May. The paper has not been peer reviewed.
In the Danish central graben, tight chalk reservoirs have been developed successfully through drilling, completion, and stimulation of long horizontal wells. These fields, developed since the early 1970s, are operated on behalf of a joint venture, the Dansk Undergrunds Consortium (DUC). One of the most successful technologies used in these fields is the controlled-acid-jetting (CAJ) technique.
Lower Cretaceous Formation, Central Graben
Fig. 1 shows the major producing fields of the DUC area. The Lower Cretaceous reservoir contains significant in-place oil volumes. Fig. 2 shows the thickness map of the Tuxen and Sola Lower Cretaceous formation in the central graben. This formation historically has posed a challenge to development because of its extremely low permeability; in addition, the formation is soft, highly heterogeneous, and has significant clay content in some areas. Thicker Lower Cretaceous reservoir sections in the Valdemar field have been propped-fracture stimulated successfully. Acid stimulation is preferred for the thinner sections; however, early attempts at matrix acid stimulation were very disappointing. Recently, the need to re-enter a well for maintenance allowed three zones to be selectively restimulated with improved execution techniques and a more appropriate acid formulation. Production increase following restimulation of this first well was very encouraging, and the lessons learned were applied to a second well.
The Lower Cretaceous formation is characterized by a high content of insoluble residue (IR), consisting mainly of clay with subordinate amounts of quartz, rare pyrite, and organic material. Porosity correlations were developed from core data and by petrophysical evaluation of logs. The porosity varies considerably, but is generally remarkably high. While the primary variation in porosity was linked directly to the IR content of the facies, factors such as pore pressure and depth of burial/compaction also had an influence.
On the basis of the formation core data, the Lower Cretaceous would not be considered a good candidate for matrix acid stimulation. It is well established, however, that low-permeability reservoirs can be economically produced by long, horizontal wellbores that effectively maximize reservoir contact.
Technology Focus: EOR Operations (June 2013)
Authors: Bonet-Cunha Luciane 
Published: February 2015

Technology Focus
Enhanced oil recovery (EOR) operations are designed to follow deterministic and detailed procedures, with planned actions for the people executing them and expected reactions from the system (reservoir) to which operations are being applied. However, a number of hurdles need to be overcome to reach a successful action/reaction, problem-free status in EOR operations. One challenge is that success depends on insightful subsurface knowledge. Nevertheless, as is well-known to people in the oil industry, information about key reservoir properties is scarce and limited to point measurements inside the wells and nondestructive remote data at much lower resolution. Thus, there is great uncertainty in the process of describing the reservoir, and EOR operations must be planned, developed, and managed in this uncertain environment. To reduce uncertainty, the strategy should be to focus at first on a robust EOR screening and design process, gathering as much reservoir data as possible. In the second stage, technically sound pilot studies can increase knowledge and reduce operating risk.
Time and resources spent on those two topics have provided oil operators with improved EOR-management techniques, despite the underlying reservoir uncertainties, with fewer surprises and less stress and ambiguity. Like a gold-medal team in a synchronized swimming event, despite participants being outside their natural and well-known environments, training and teamwork are responsible for a unique, precise, and quite deterministic result.
The papers featured this month will give you only a few examples of the vast amount of high-quality material that was published last year and will illustrate how EOR operations, though challenging, can be tackled on the basis of technological advances in data acquisition and careful analysis and interpretation of reservoir data during screening and pilot-study phases. I hope you will enjoy the reading and will search for additional papers in the OnePetro online library.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 164048 Novel Scale Remediation for Steam-Assisted-Gravity-Drainage Operations by Timothy Cheung, Shell Canada, et al.
SPE 155123 Industrial Experience in Seawater Desulfination by Pierre Pedenaud, Total, et al.
SPE 157996 Optimizing Water-Injection Rates for a Waterflooding Field by Feilong Liu, Chevron Energy Technology Company, et al.
SPE 159620 A New Approach To Deliver Highly Concentrated Surfactants for Chemical Enhanced Oil Recovery by Julian Barnes, Shell Global Solutions
Albacora Subsea Raw-Water Injection
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 24167, ’Albacora Subsea Raw-Water-Injection Systems,’ by L. Buk Jr., C.A. Andrade, J.B. Azevedo, E.J.J. Coelho, O.C. Costa, C. Kuchpil, A.G. Siqueira, and A.L.S. Souza, Petrobras, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.
To increase the oil recovery in the Albacora field, significant water injection is required that was not considered in the initial project-development phases. Technical and economic constraints do not allow the use of conventional seawater-injection plants because current production units have no area available to implement a conventional water-injection system. Application of subsea raw-water-injection (SRWI) systems in the field involved challenges that required a detailed and systematic analysis to evaluate the technical feasibility and establish requirements for implementation. This alternative enabled seawater to be injected into the reservoir with minimum treatment by use of equipment installed on the seabed.
Introduction
In some offshore fields, mainly mature fields, the addition of conventional technologies to topside facilities can constrain the use of seawater injection. Conventional systems require the installation of too many pieces of equipment at the production units, which requires large areas that sometimes are not available. Other restrictions include swivel constraints on floating production, storage, and offloading vessels (FPSOs) and load limitations.
One alternative is SRWI technology in which most of the system is installed at the seabed and seawater is injected with minimum treatment. This system has minimal effect on the topside- facilities footprint. The SRWI alternative involves technical challenges that include seawater compatibility with the reservoir rock and fluids, microbiological control, corrosion, water properties, reliability of the subsea equipment, and power, which limit the use of this technology in some scenarios.
Petrobras established a project to evaluate and develop this technology, involving technical-feasibility studies and evaluation of various scenarios and preliminary specifications. During this project, Albacora-field reservoir studies indicated the need for large amounts of water injection, and SRWI became the only economically feasible alternative identified to address this demand.
Albacora Field
Albacora is a giant field in the Campos basin, approximately 100 km offshore Brazil, covering an area of approximately 235 km2, with water depths of 250 to 1100 m. The field was discovered in September 1984 and has an estimated oil-in-place volume of 4.4 billion bbl. Pilot-phase production started in 1987 with the FPSO P.P. Moraes. In 1993, a second development phase started with the semisubmersible P-24, which was replaced later by the definitive production system with two production units: the semisubmersible P-25 and the FPSO P-31, installed in 1996 and 1998, respectively. Field oil production peaked in 1999.
EOR: Next Frontier for Unconventional Oil
Authors: Joshi Sada 
Published: February 2015

Guest editorial
Recent headlines declared that the United States could end net oil imports by 2037. That finding, by the US Energy Information Administration (EIA), is the agency’s first-ever projection—albeit under a high-resource scenario—of possible oil self-sufficiency for America.
It is a stunning reversal of a trend. US net oil import dependency was at 60% as recently as 2005 and thought to be headed to 70% within a decade. Instead, today it is about 33% and dropping.
Many of my colleagues in the oil and gas industry and I have long believed that achieving such a milestone was possible, if only the right combination of technology, economics, and political will could come together. We understood the scope of the vast untapped hydrocarbon bounty in the US, recognizing that half of its identified oil endowment of nearly three-quarters of a trillion barrels of oil is untapped. That is why the US leads the world in the application of improved oil recovery (IOR) and enhanced oil recovery (EOR) technologies.
Much of the credit for the surge in US oil production goes to the advances in horizontal drilling and hydraulic fracturing applied to massive shale and other tight oil rock formations. Indeed, even under the EIA’s reference case, shown in Fig. 1, tight oil sustains overall US production for many years at a level nearly twice what expectations were just a decade ago. Both technologies essentially qualify as IOR, bolstering the claim that, in fact, IOR is responsible for America’s energy revolution.
Carbon Capture: Saudi Aramco's Carbon Management Program
Authors: Al-Meshari Ali A. , Muhaish Fahad I. , Aleidan Ahmed A. 
Published: February 2015

Carbon Capture
Many industries are doing their fair share to address climate change and combat greenhouse gas (GHG) emissions. For the oil and gas industry, meeting global and domestic energy demands while addressing climate change presents numerous challenges but also opportunities. With the unprecedented level of international attention on climate change in recent years, Saudi Aramco is keen to play a leading role in addressing the main issues.
Technological solutions, such as advanced and highly efficient hydrocarbon technologies and carbon capture and storage (CCS), are key elements to addressing climate change rather than aiming at dispensing of fossil fuels in a world of global interdependence. Almost all scenarios indicate that the world will continue to depend on hydrocarbon- based energy sources for the foreseeable future. It is therefore prudent to adopt collaborative hydrocarbon research and develop solutions for CO2 geological sequestration, subsurface utilization of CO2, cost reduction for CO2 capture from fixed sources, and explore new technologies to increase efficiency and reduce CO2 emissions from mobile sources.
Acidizing a Sandstone Formation Successfully in the Gulf of Cambay
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164631, ’Overcoming Challenges While Acidizing Sandstone Formation Successfully in the Gulf of Cambay, Offshore India,’ by Sergey Stolyarov and Anwar Alam, Baker Hughes, prepared for the 2013 SPE North Africa Technical Conference and Exhibition, Cairo, 15-17 April. The paper has not been peer reviewed.
This paper describes a matrix-acidizing campaign executed successfully in the Gulf of Cambay on the west coast of India. In initial laboratory tests and during simulation runs, the goal was to design a preflush/ acid/post-flush system to best suit challenging reservoir conditions while also considering offshore logistics. After pumping the system in one well, the system design, pumping procedures, and volumes were modified to improve results further in the next well.
Introduction
The offshore field, located in the Arabian Sea off the western coast of India, has been on production since 1997 (Fig. 1). The field covers an area of 1471 km2 and lies 160 km north/northwest of Mumbai. The reservoir consists of a stacked series of sands deposited in the Lower Miocene and Oligocene. The field has up to 13 different Olio-Miocene gas-bearing sands separated by shales. Reservoir-sand permeability ranges from 100 md (in shaly beds) up to 5,000 md in clean sand beds. Because of the unconsolidated nature of the reservoir sands, gravel-pack screens are a typical well completion in the field.
Technology Focus: Wellbore Tubulars (June 2014)
Authors: York Pat 
Published: February 2015

Technology Focus
NORSOK (the competitive standing of the Norwegian sector), as most know, is the industry initiative to add value, reduce cost and lead time, and eliminate unnecessary activities in offshore field developments and operations.
The NORSOK-010 Rev. 4 Standard document defines requirements and guidelines regarding well integrity in drilling and well activities. It defines well integrity as the “application of technical, operational, and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well.” The NORSOK standard focuses on establishing well barriers by use of well-barrier elements in conjunction with their acceptance criteria, their use, and monitoring of integrity during their life cycle. Further, it defines a well-barrier element as a physical element that in itself does not prevent flow but, in combination with other well-barrier elements, forms a well barrier.
The standard focuses strongly on the establishment of well barriers and well-barrier elements and on how these are accepted and monitored to prevent loss of well integrity that ultimately could lead to a loss in wellbore-fluid containment. The general principle of the two-barrier concept is that two well barriers should be in place at all times to ensure the provision of well integrity. In the drilling phase, the primary well barrier is typically the fluid column. Secondary well-barrier elements can be the in-situ formation, casing cement, casing, wellhead, high-pressure riser, or drilling blowout preventer.