bluuebunny/crossref_metadata_2025_split huggingface dataset:
Offshore Industry Gets a Fresh Look at Foamed Cement
Authors: Jacobs Trent 
Published: February 2015

Foamed Cementing
An ongoing research project started nearly 3 years ago by the US Department of Energy’s National Energy Technology Laboratory (NETL) is shedding new light on what really happens to foamed cement as it is pumped deep down offshore wells during completions.
The genesis of the research was the 2010 subsea blowout of the Macondo well in the US Gulf of Mexico (GOM) that destroyed the Deepwater Horizon drilling rig and claimed 11 lives. In the aftermath, the industry faced tough questions about the limits of its technology and the US government tapped NETL to improve the safety of offshore development.
After 6 months of interviewing experts in the offshore industry, lead researcher and NETL scientist Barbara Kutchko, who served as an objective expert in the federal litigation over the Macondo incident, decided to focus on foamed cement based on the clear need for more information about how the technology performs outside of the laboratory.
“I knew there was a big issue with foamed cement,” Kutchko said. “There was not a lot of research behind it. Foamed cements are mixed under atmospheric conditions, yet there was little known about its properties in the wellbore.”
Cement specialists who are lending their expertise to the research said initial findings confirm long-held theories about how the 25-year-old technology performs. As the work progresses, they also said it may result in improvements in how foamed cement is made and applied.
Among the things that the research has proved thus far is that as the density of the bubbles inside the foamed cement varies, so does its strength. When the bubbles are smaller, the chances of them joining together to form a larger bubble is less likely, resulting in higher quality and stronger cement.
Foamed cement was first introduced in the early 1980s as a low-density substitute for conventional cement and can be pumped more easily down deep wells. In the offshore environment, where deck space and weight are always at a premium, lighter-weight foamed cement has also greatly improved the logistics of completing subsea wells.
ADIPEC: Oil Price Decline Won't Affect Long-Term Strategy
Authors: Henni Abdelghani 
Published: February 2015

Conference Review - 2014 ADIPEC
The decline in oil prices will not affect the long-term strategy of national oil companies in the Middle East, ministers and senior executives said at the opening of the 30th edition of Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC) held in November.
Speaking during the ministerial panel session, UAE Minister of Energy Suhail Al Mazrouei said oil producers are not panicking about the decline in prices. Abdalla El-Badri, the OPEC secretary general, was optimistic about future oil prices. “Please don’t panic; things will fix themselves,” he said. The same view was shared by Ali Al Omair, Kuwait’s oil minister, who said that oil prices will rise again.
Meanwhile, Abdulla Nasser Al Suwaidi, director general of Abu Dhabi National Oil Company (ADNOC), said during the inaugural session that energy markets and projects must be driven by long-term stability and not short-term instability and price volatility.
“The recent oil price decline has put the industry in the spotlight,” he said. “But despite this decline, all our projects are on track without any delay. In fact, we are expecting the startup of various oil and gas projects that will increase our output, including the Shah gas field, which will boost our gas output by almost 1 Bscf/D.”
In addition to the Shah gas field, operated by Al Hosn Gas, the Abu Dhabi Company for Onshore Oil Operations (ADCO) is set to invest a further USD 5 billion to USD 7 billion to meet its production target of 1.8 million BOPD by the end of 2017. ADCO, which operates the onshore oil fields that are responsible for about 40% of the country’s output of 2.85 million BOPD, said the commitment to pump more oil will help the UAE meet its target to increase capacity to 3.5 million BOPD by 2017.
ADCO currently has a capacity of 1.613 million BOPD and invested about USD 5 billion in the first phase of the expansion program through the end of 2012, increasing production by 225,000 BOPD.
Causal Factors and Improvement Measures Related to Well Control
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163775, ’Risk of Major Accidents: Causal Factors and Improvement Measures Related to Well Control in the Petroleum Industry,’ by Elisabeth Lootz and Monica Ovesen, SPE, Petroleum Safety Authority Norway, and Ranveig Kviseth Tinmannsvik, Stein Hauge, Eivind H. Okstad, and Inge M. Carlsen, SPE, SINTEF, prepared for the 2013 SPE Americas Exploration and Production Health, Safety, Security, and Environmental Conference, Galveston, Texas, USA, 18-20 March. The paper has not been peer reviewed.
From 2009 to 2010, there was an increase in the number of well-control incidents on the Norwegian continental shelf reported to the Petroleum Safety Authority Norway (PSA). This, together with the Deepwater Horizon accident in 2010, prompted PSA to initiate a comprehensive investigation into the causes and possible mitigating measures related to well-control incidents. This paper details the findings of the study.
Introduction
The PSA report Trends in Risk Level in the Norwegian Petroleum Activity (RNNP) has been released on an annual basis since 2001. The RNNP aims to measure and improve health, safety, and environmental conditions in the Norwegian petroleum industry both offshore and onshore. The project includes indicators related to major accidents, personal injuries, and working-environment factors.
The project monitors risk level through the use of a number of indicators: incident data (well-control incidents, hydrocarbon leaks, and personal injuries), data describing performance of technical barriers, maintenance data, and working-environment indicators (noise, ergonomics, and chemicals). Multiple methods, both quantitative and qualitative, are used to investigate and monitor changes in risk level. Interviews, field work, and a survey targeted at all employees on facilities onshore and offshore are used alongside more-traditional incident and near-miss reports.
Organizational details about the Norwegian petroleum industry that were fundamental to the collaborative effort that made the study possible are detailed in the complete paper.
The main research questions addressed in the present study included the following:
What are the key human, technical, and organizational causes of well-control incidents?
What are the most important measures proposed/implemented to reduce the number of well-control incidents?
Is there correspondence between identified causes and proposed/ implemented measures?
How can the petroleum industry improve its efforts to reduce the number of incidents further?
Method
The study was conducted by an experienced interdisciplinary research team on behalf of PSA. An interdisciplinary expert group was established simultaneously within PSA. The expert group participated in the study design, ensuring that relevant literature and important problems were addressed, and followed the study as it progressed through different phases. All data were collected under a strict confidentiality agreement.
Technology Focus: Decommissioning and Abandonment (January 2015)
Authors: Thornton Win 
Published: February 2015

Technology Focus
A recent report titled “UK Continental Shelf (UKCS) Maximizing Recovery Review” by Sir Ian Wood (www.woodreview.co.uk) provides an interesting view into late-life-production and decommissioning issues in a mature basin. It is a good treatment of the issues specific to the UK sector of the North Sea, and I believe that many of these issues (and possible solutions) can apply more broadly to our global maturing offshore infrastructure.
Here are a few highlights from the late-life/decommissioning recommendations from the Wood Report.
Asset Stewardship Strategy—Ensure focus on stewardship of assets and infrastructure to maximize the economic recovery from fields and with consideration to adjacent resources.
Regional Development Strategy—Ensure the development of resources on a regional, rather than solely a field, basis.
Infrastructure Strategy—Ensure that the life of the existing infrastructure is prolonged to facilitate the production and transport of regional resources.
Technology Strategy—Ensure that existing technologies are deployed to their fullest and that relevant new technologies are developed and deployed successfully.
Decommissioning Strategy—Ensure that key assets are not decommissioned prematurely to the detriment of production hubs and infrastructure, and ensure that decommissioning is executed in a safe, environmentally sound, and cost-effective manner with sufficient early planning and coordination.
It can be seen that actualization of the recommendations from the Wood Report could drive the operator toward a life-of-field or even a life-of-region planning perspective. As the operator approaches the end of a field’s life, the remaining value may lie predominantly in a low-cost decommissioning delivery coupled with some upside value from the retention of critical infrastructure to enable maximum regional resource recovery. Actualizing this value will require the operator to begin late-life and decommissioning planning much earlier than cessation of production. The operator will need a process to assess the field’s timing and value drivers, communicate them externally to other stakeholders (operator, supply chain, and regulator), and periodically update and adjust them as time and conditions change. The challenge is that, at present, there does not exist a mechanism to facilitate this level of collaboration. We should keep an eye on the developments in the UKCS in the wake of the Wood Report. The efforts there may provide a solution template that can be considered globally. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 163942 Plug and Abandonment of a Deep High-Pressure and High- Temperature Gulf of Mexico Well Using Coiled Tubing: A Case History by Brendon Webb, Schlumberger, et al.
SPE 168517 An Optimized Protocol To Expedite Pit Closure by Rob Hoffmann, Chevron, et al.
SPE 170949 Environmental Risk and Well Integrity of Plugged and Abandoned Wells by George E. King, Apache, et al.
Interview with 2015 SPE President Helge Hove Haldorsen
Authors: Haldorsen Helge Hove , Donnelly John 
Published: February 2015

President's interview
Where do you see SPE growing in membership in the short to medium term?
SPE is a global organization on a mission to share. Petroleum engineers have a passion for their business and SPE has a passion for helping them, connecting them, and providing them with evolving best practices. Also, SPE wants everyone who works in exploration and production (E&P) to help shape the industry’s future since we know that attacking E&P challenges from different perspectives always secures smarter solutions. Therefore, the future of E&P starts with everyone, everywhere. With nonmember petroleum engineers throughout the world, our membership drive will continue because SPE gets better with more perspectives and more diversity. Reed’s Law states that the utility of networks increases exponentially with size. SPE members in turn get better in their trade because they joined SPE. My main point is that this is not just about volume and growth in membership for growth’s sake; it is about value and because we are talking about producing sufficient energy to meet global demand—it is about a win-win for all.
SPE has grown tremendously during the past 10 years, from 60,559 members in 2003 to 124,528 at the end of 2013, including student memberships. An overview of SPE’s current professional membership shows centers of gravity in North America, among the majors and oilfield service companies (over independents and engineering firms); among drilling, production, and reservoir engineers (over facilities, management, and health, safety, and environment [HSE] professionals); and among seniors (over juniors).
Global SPE membership potential can be estimated by function and aggregated by country and then globally. SPE’s total global membership potential was recently estimated to be over 200,000 professionals. The logical way forward would then be for SPE to focus its forward membership drive on the countries with the largest membership potential and where SPE currently has low penetration rates. Other important membership growth considerations are: In what can be called mature SPE markets such as the United States, Canada, Norway, and the United Kingdom, we need to make sure that every graduating petroleum engineer joins SPE, that underrepresented disciplines get a membership boost (geology and geophysics, management, facilities, and HSE), and that more professionals working for independents join SPE. With Mexico opening, it is important that SPE quickly start collaborating with existing Mexican societies and associations to find new and innovative ways to share and co-evolve to the benefit of Mexican energy professionals. Mexican professionals will contribute to the global community with unique functional and operational skills in a number of key areas, from the evaluation and production of offshore carbonate reservoirs to offshore improved oil recovery with massive nitrogen injection. We also need to become more involved in emerging petroleum-producing countries, such as Myanmar, Tanzania, Mozambique, Kenya, and Ghana.
Technology Focus: Field Development Projects (October 2014)
Authors: Rebelo Mauricio Pestana 
Published: February 2015

Technology Focus
Managed-pressure drilling (MPD) is a relatively new technology, but its use is becoming more and more frequent in the industry.
The principle of MPD is to provide full control of the annular-pressure profile during drilling.
MPD is allowing the possibility of drilling wells that could not be drilled with conventional methods, where the bottomhole pressure is controlled exclusively by controlling the density of the drilling fluid.
Wells with severe-lost-circulation zones are an example of scenarios where MPD is bringing good results.
Although the use of MPD is helping drilling operation by allowing better pressure control in the annulus, there are also new risks to be taken into consideration. When using MPD, drillers normally are working in a narrow window between pore and fracture pressure, so the margin of error is smaller. The well-control process with MPD is also different from that of conventional drilling.
Because of the risks involved, appropriate training is mandatory for all personnel involved with the operation: everyone from people on the project team to those working on the rig. This is the key for the success of MPD.
Please enjoy the papers selected, one of which (SPE 165893) includes a discussion on MPD. JPT

Recommended additional reading at OnePetro: www.onepetro.org.
OTC 24358 Optimized Well-Path- Planning Decisions in Real-Time Monitoring Operations by Célia Falcone, Petrobras, et al.
SPE/IADC 163425 Optimal Bit, Reamer Selection and Operating Procedures Improve Hole-Enlargement Performance in Deepwater Gulf of Mexico by T. Ho, Baker Hughes, et al.
SPE 164018 Integration of Fracture, Reservoir, and Geomechanics Modeling for Shale-Gas-Reservoir Development by Jugal K. Gupta, ExxonMobil Upstream Research Company, et al.
Combined Geostatistics and Bayesian Updating Optimize Drilling in Shale-Gas Plays
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164816, ’Combining Geostatistics With Bayesian Updating To Continually Optimize Drilling Strategy in Shale-Gas Plays,’ by B.J.A. Willigers, BG Group; S. Begg, University of Adelaide; and R.B. Bratvold, University of Stavanger, prepared for the 2013 EAGE Annual Conference and Exhibition incorporating SPE Europec, London, 10-13 June. The paper has not been peer reviewed.
The development of an economically efficient drilling program in shale-gas plays is a challenging task, requiring a large number of wells; even with many wells, the average well production and the variation of well performance (economics) remain highly uncertain. The ability to delineate a shale play with the fewest number of wells and to focus drilling in the most productive areas is an important driver of commercial success. Here, we present a new methodology for improving the economic returns of shale-gas plays.
Introduction
The methodology proposed in this study informs the development of drilling policies for shale-gas opportunities by use of a probabilistic model that accounts for the uncertainty in the chance of success (COS) and its spatial dependency. The model developed in this study shows how a prior view of the COS across a shale-gas play is updated as more wells are drilled. Inferred chances of success of undrilled well locations allow decision makers to react to newly arriving well data and optimize the development of a shale-gas resource.
The main contributions of this paper are (1) to establish and quantify any spatial dependencies between the performances of shale-gas wells, an assessment based upon data from the Barnett shale; (2) present a comprehensive method for updating COS probabilities consistently with the arrival of new information in a play with spatial dependencies; and (3) demonstrate the approach through an analysis of data from the Barnett shale.
For a discussion of previous work performed in uncertainty resolution in inconventional gas plays, including the role played by spatial dependency, please see the complete paper.
Shale-Gas Economics in the Study Area
Well Data. The investigated area is located in the eastern part of the Mississippian Barnett shale in the Fort Worth basin in Texas (Fig. 1). The study area covers 2100 km2 and straddles Johnson, Tarrant, and Ellis Counties. A set of 2,901 horizontal wells has been analyzed; 2,064 of these are located in the “Training” area (see later reference in this subsection). Well data include well location; date of completion; first 6-, 12-, or 24-month cumulative gas production; and the length of the well. The data originate from the US Energy Information Administration (www.eia.gov).
Oman Champions EOR in the Middle East
Authors: Henni Abdelghani 
Published: February 2015

Oman EOR
Although famous for its abundant oil fields, generations of production in the Middle East is putting sharper focus on ultimate recovery from these fields.
The issue is particularly pressing for Oman. Output in the country’s maturing oil fields peaked in the 1990s and Petroleum Development Oman (PDO), the national oil company, spearheaded the implementation of enhanced oil recovery (EOR) techniques with its first trials in the late 1980s.
For Oman, EOR remains a major strategic option in its challenge to increase recovery and to meet long-term production requirements. Substantial efforts have been directed at investigating cost-effective ways in which production levels from existing fields can both be sustained and increased.
Oman’s first EOR program was completed in 1989 and led to progress in experience gained and reduction in technical and cost uncertainties. Oman has seen considerable investment in a range of EOR technologies to produce heavy oil, and a host of other countries in the Middle East and India have been encouraged by Oman’s success. Between 2001 and 2007, Oman’s oil production fell by 27%, but by 2009, due mostly to EOR projects, oil production had increased by 17%.
In a region where national oil companies essentially control all the hydrocarbon resources, Oman’s partnership between national and international oil companies stands out, also because it has been an important driving force behind the country’s EOR rollout. The growth in use of EOR techniques has increased the cost of Oman’s oil production but also has boosted output by 180,000 BOPD to 200,000 BOPD. Total Oman production is 940,000 BOPD. “In comparison with primary oil extraction, which sometimes costs only USD 4-5 per barrel, EOR techniques come at an expense of USD 10-12 per barrel,” said Salim bin Nasser Al-Aufi, undersecretary of the Ministry of Oil and Gas in Oman.
The EOR techniques that Oman has used include chemical EOR as well as thermal and miscible gas injection. The choice of EOR technology is based on the reservoir depth and oil viscosity.
PDO’s Experience
PDO, which produces more than 80% of Oman’s oil production, commissioned its first EOR project in 2004, and expects that EOR will contribute to 25% of total liquids production by 2020. “We have had to move into a significant program of EOR technologies. We are the only company in the world that has thermal, miscible, and polymer chemical-injection recovery mechanisms within the same concession, all of which are in full-scale implementation,” said Raoul Restucci, managing director of PDO.
Development Optimization of a Marginal Oil Field in Bohai Bay, China
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16669, ’Development Optimization of a Marginal Oil Field in Bohai Bay, China - Integrated Solutions To Overcome Challenges in Offshore Horizontal-Well Construction,’ by Chaomin Nie, Yongsheng Zhao, Lv Tan, Yong Jia, and Gang Zhai, China National Offshore Oil Corporation Tianjin, and Parlindungan Monris Halomoan, Xu Chong Hui, Wang Yong, Wang Fei, and Dong Jianyi, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28.March. The paper has not been peer reviewed.
Nine horizontal wells, including one injector well, were drilled in a marginal oil field in Bohai Bay, China. Seismic inversion indicates that sand properties and connectivity vary dramatically across the field. A multiple-aquifer system was apparent, and the gas/oil-contact (GOC) and oil/water-contact (OWC) levels were unknown. Furthermore, the only well control was from three vertical exploration wells and two directional offset wells. An advanced distance-to-boundary well-placement technique using azimuthal deep-directional electromagnetic logging-while- drilling (LWD) technology was applied to overcome these challenges and to enhance reservoir understanding.
Introduction
The BZ oil field is located in the southern part of Bohai Bay, approximately 160 km southeast of Tanggu, Tianjin (Fig. 1). It is a small oil-bearing area (9.km2) isolated by secondary faults generated at different geological periods and by stratigraphic depositional borders.
Two other producing oil fields are located in the northern and western parts of the BZ area. Although the original oil in place (OOIP) of the oil field is estimated at only 1261.89×104 m3, this marginal oil field is expected to be profitable to develop and put into production by sharing the facilities of the other two oil fields.
The BZ structure is part of the complex fault system on the northwest side of the Huanghekou depression on the west side of the Bonan uplift. Because of the oil field’s isolation, a multiple-aquifer system exists. A pilot study based on core and sequence-stratigraphy analysis of multiple wells shows that the reservoirs are distributary channel sands of a shallow lake delta plain. The channel sands have medium-to-high porosity and permeability. The seismic-data analysis suggests that the properties may vary laterally. Meanwhile, uncertainty in the top gas and bottom water levels adds to the complexity of this field. The GOC and OWC levels were unknown before this horizontal-well-drilling program.
Horizontal-Well-Drilling Program
Two platforms were designed to develop this complex oil field: BZ-A platform, to drill 11 wells, and BZ-B platform, to drill five wells. Among these 16 wells, 10 horizontal wells were designed as producer wells, five deviated wells were designed as injector wells for formation-pressure maintenance, and one deviated well was designed to supply water for the injector wells.