bluuebunny/crossref_metadata_2025 huggingface dataset:
Techbits: Learnings From the SEG/SPE/ARMA Injection-Induced Seismicity Workshop
Authors: Maxwell Shawn
Published: February 2015

Techbits

In September, a technical workshop was held on the topic of injection-induced seismicity in Banff, Canada. It brought together industry and technical experts to discuss the increasingly important topic of induced seismicity associated with various injections during oil and gas activities.

The event was cosponsored by the Society of Exploration Geophysicists (SEG), the Society of Petroleum Engineers (SPE), and the American Rock Mechanics Association (ARMA), serving as a followup to a previous meeting on the topic held in Broomfield, Colorado, in 2012.

More than 120 professionals participated, with the majority traveling from the United States (60%) and Canada (30%), and some from Europe (10%) and one each from Japan and Colombia. The attendees represented oil and gas companies (34%), academia (25%), service companies (25%), and government organizations including national laboratories, geological surveys, and regulatory bodies. Similar to the workshop in Broomfield, the majority of the participants were geophysicists (both industry geophysicists and earthquake seismologists) with engineers and geomechanicists making up the rest of the group.

Nearly 50 technical presentations made up the program that covered case studies, various techniques to model the phenomena, seismic hazard and risk, and industry protocols to mitigate the problem. The workshop was organized through a committee consisting of Dave Eaton, University of Calgary; Hal Maccartney, Pioneer Resources; Julie Shemeta, MEQ Geo; Mike Fehler, Massachusetts Institute of Technology; Norm Warpinski, Pinnacle/Halliburton; Pat McLellan, Talisman Energy; Rod Gertson, Devon Energy; and was chaired by Shawn Maxwell, IMaGE.

It was interesting to compare and contrast the two workshops to see how experience, understanding, and attitudes have changed during the period. The Broomfield meeting was held at a time when concerns about injection-induced seismicity were just beginning and the meeting was primarily intended to educate the industry about the issue. As described in a Broomfield workshop report published in SEG’s The Leading Edge and SPE’s Journal of Petroleum Technology, key facts were established.

When Does Seismicity Occur?

For example, only a small proportion of injection wells have induced seismicity, including geothermal, waste injection, and hydraulic fracturing operations. The seismicity occurs when preferentially oriented faults close to the point of slipping in the geologic stress field have stress and/or pressure changes that cause the fault to slip. Seismicity also can occur after the injection has ceased and may occur at some distance from the actual injection point, which can lead to uncertainty identifying injection as a causal factor.
Working Outside the Lines
Authors: Rassenfoss Stephen
Published: February 2015

SPE Technical Directors' 2015 Outlook - David Curry, Olivier Houze, Shauna Noonan, Howard Duhon, Trey Shaffer, J.C. Cunha, Dan Hill

SPE’s technical directors are focused on problems that require working outside the bounds of their discipline. Stubbornly low recovery rates from unconventional reservoirs led to a collaboration between the directors in drilling and reservoir engineering because cooperation is required to understand opportunities, find solutions, and apply what has been learned.

Fiber-optic cable’s potential to improve shale well performance led the production director to look for ways to increase the number of applications offering multiple benefits, which touches on a wide range of concerns over the life of a well.

Rapidly escalating project costs led the projects, facilities, and construction director to look outside the profession for ways to measure and manage project complexity. The goal is to recognize the time and money needed to integrate complex systems, and look for ways to manage those issues.

Overruns are also often linked to social concerns that never appear on a project’s list of technical risks. The director for health, safety, security, environment, and social responsibility wants the industry to think more about the broader impact of its projects, which can lead to opposition from affected communities.

Reaching all the above goals will depend on technically skilled people who see the big picture, which is why the director for management and information is emphasizing the need for engineers to broaden their perspective to better understand the business side of the equation, and profit from ever-more data and new approaches.

A seventh perspective has been added to the discussion: a director representing academia. The first person to hold the job, Dan Hill, the head of the department of engineering at Texas A&M University, has set out to understand the needs of universities globally.

The fact that directors representing reservoir interpretation and drilling and completions are collaborating on ways to improve recoveries from unconventional reservoirs says something about what is required to do that. David Curry, the Director for Drilling and Completions, and Olivier Houzé, the Director for Reservoir Description and Dynamics, say cooperative effort is essential for this project.
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.
Coal-Seam-Gas-Field Management: Forecasting During Shutdown and Recovery
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167088, ’Coal-Seam-Gas-Field Management: Well-Performance and Production Forecasting During Shutdown and Recovery Operations,’ by S. Magee, T. Ogilvie, and C. White, Origin Energy, prepared for the 2013 SPE Unconventional Resources Conference and Exhibition - Asia Pacific, Brisbane, Australia, 11-13.November. The paper has not been peer reviewed.

Queensland, Australia, is currently host to a number of coal-seam-gas (CSG) to liquefied-natural-gas (LNG) projects under development. However, the need to build field deliverability before the availability of export gas markets presents a significant challenge. CSG wells must be dewatered; during this process, gas production may need to be constrained. The ability to manage and forecast production performance in a field-turndown scenario is therefore critical. A study of production data from CSG-production-interruption events was conducted to determine how wells reacted to turndown of gas-production rates.

Introduction

There are currently three major CSG-to-LNG projects under construction in Queensland. A number of other projects are also proposed and are currently in various stages of planning and approval.

The transition from a domestic gas market to an export LNG market presents many opportunities and challenges for gas producers. When the LNG-export facilities are commissioned, the gas demand markedly increases over a short period of time. To ensure the best return on capital investment and to satisfy export contracts, the use of these export facilities needs to be maximized as soon as possible after commissioning. To optimize field output at the time that downstream facilities become operational, the CSG reservoirs must be de watered in advance, resulting in an increase of produced-gas volumes along with the early water production. One challenge for upstream producers is how to manage field deliverability during a period (the ramp period) when there is little ability for existing markets to absorb significant increases in gas supply. Possible solutions include gas storage, flaring, and the constraining of gas production while continuing to dewater the reservoir (turndown), or some combination of these and other strategies. The optimum strategy is likely to be a function not only of reservoir performance but also of the various commercial, operational, and project-execution constraints faced by each operator.

Review of Historical Production Data

Historically, field turndown in the areas of study has been achieved through the selective choking or shut-in of individual producing wells. The primary factors in well selection have been gas and water production, completion status, and liquid-lift calculations.
The SPE Leadership Academy: A New Training Initiative
Authors: Beckwith Robin
Published: February 2015

Learning Leadership

The SPE Training and Member Programs departments took on the task of creating an intensive and industry-specific means to help spur the development of leadership abilities particularly of younger E&P professionals.

It has long been known that a training gap exists in the oil and gas industry as less-experienced professionals move to leadership roles earlier in their career than they would have in the past. This is because a large population of seasoned professionals has been and is still transitioning into retirement. SPE is strong on technical knowledge, but needed to team up with a partner that understood human behavior in global organizations.

So, with SPE’s knowledge about training, the E&P industry, and the challenges that confront E&P leaders, and with Kiddy and Partners’ knowledge about global business psychology—the two organizations collaborated to develop the SPE Leadership Academy.

The first 3-day course was conducted in Dubai, 30 September to 2 October 2014. And the second will be held 2 through 4 December 2014 at SPE’s Houston Training Center.

More information can be found at www.spe.org/training/courses/SLA.php.

A Guided Examination of Oneself and Others Within E&P-Specific Scenarios

The SPE Leadership Academy was developed for those transitioning into a leadership role, those identified by management as potential leaders, and those who aspire to be leaders. The academy is structured around the philosophy that, by delving into a guided examination of oneself and others within roles and situations encountered in the E&P industry, participants can expedite development of their ability to lead others effectively in multidisciplinary, multi-stakeholder projects, jobs, and situations.

The following outlines the structure of the 3-day curriculum, with the types of questions participants can expect to explore through such means as the Myers-Briggs Type Indicator, E&P-specific role-playing exercises, questioning and listening techniques, homework exercises, discussion and feedback, and presentation techniques and practice.
A Semianalytical Forecasting Method for Unconventional Gas and Light Oil Wells: A Hybrid Approach for Addressing the Limitations of Existing Empirical and Analytical Methods
Authors: Clarkson C. R. , Qanbari F.
Published: February 2015

The rapid pace of exploitation of unconventional gas and light oil plays in North America has necessitated the development of new production-forecasting methodologies to aid in reserves assessment, capital planning, and field optimization. The generation of defendable forecasts is challenged not only by reservoir complexities but also by the use of multifractured horizontal wells (MFHWs) for development.

In this work, a semianalytical method (SAM) is developed to provide a solid theoretical basis for forecasting. The technique is analytical in that it uses the methods of Agarwal (2010) to calculate contacted oil in place and contacted gas in place (COIP/CGIP) from production rates, flowing pressures, and fluid properties. The rate-normalized pressure (RNP) derivative (RNP′) is a key component of the calculation; pseudopressure is used for gas cases. The technique is also empirical in that an empirical function is fitted to the resulting COIP/CGIP curve vs. time. Although the method is flexible enough that any equation can be used to represent the COIP/CGIP curve, and hence, the sequence of flow regimes exhibited by MFHWs, the equation must be capable of being integrated to allow the extraction of RNP. The stabilized COIP/CGIP during boundary-dominated flow (BDF) must be specified for forecasting—thereafter, the method uses a material-balance simulator to model BDF. Hence, if the well is still in transient flow, a range in forecasts may be generated, depending on the assumed stabilized COIP/CGIP.

The new SAM addresses some of the current limitations of empirical and fully analytical (modeling) approaches. Empirical methods, which have been adapted to account for long transient and transitional flow periods associated with ultralow-permeability reservoirs, lack a theoretical basis, and therefore input parameters may be difficult to constrain. However, empirical methods are simple to apply and require a minimum amount of data for forecasting. Analytical models, while representing the physics better, nonetheless require additional reservoir and hydraulic-fracture data that may not be available on every well in the field. The SAM proposed herein is intended to bridge the gap between empirical and modeling-based approaches—it is more rigorous than purely empirical methods, while requiring a lesser amount of data than fully analytical techniques.

The new method is tested against simulated and field cases (tight oil and shale gas). Although a simple power-law function is used in the current work to represent the COIP/OGIP curve, which appears adequate for the cases studied, one should note that wells exhibiting long transitional flow periods (e.g., elliptical/radial) will likely require a different functional form.
Experiment Study on Rheological Model of Soft Clay
Authors: Wang Donglin , Lv Qiuling , He Xiancai
Published: February 2015

This paper adopts the conventional tri-axial apparatus to respectively conduct tri-axial rheological tests on soft clay of different confining pressures by multi-stage loading vertical stress, specifically on the rheological behavior of the soft clay in Beijing area. The experimental results show that the deformation of this kind of clay has obvious time effects and nonlinear characteristics. According to the results, the test is to propose generalized Kelvin three unit and five unit model. Power function creep model and time hardening experiential models are used to describe the clay rheological behavior. The results show that, time hardening creep model is an advanced model with high accuracy, simple equations and fewer parameters and establishes a typical clay rheological model that fits Beijing area.
Graphs with maximal irregularity
Authors: Abdo Hosam , Cohen Nathann , Dimitrov Darko
Published: February 2015

Albertson [3] has defined the P irregularity of a simple undirected graph G =
(V,E) as irr(G) =?uv?E |dG(u)- dG(v)|, where dG(u) denotes the degree of
a vertex u ? V. Recently, this graph invariant gained interest in the
chemical graph theory, where it occured in some bounds on the first and the
second Zagreb index, and was named the third Zagreb index [12]. For general
graphs with n vertices, Albertson has obtained an asymptotically tight upper
bound on the irregularity of 4n3/27: Here, by exploiting a different approach
than in [3], we show that for general graphs with n vertices the upper bound
?n/3? ?2n/3? (?2n/3? -1) is sharp. We also present lower bounds on
the maximal irregularity of graphs with fixed minimal and/or maximal vertex
degrees, and consider an approximate computation of the irregularity of a
graph.
On the Bahadur representation of sample quantiles for widely orthant dependent sequences
Authors: Yang Wenzhi , Liu Tingting , Wang Xuejun , Hu Shuhe
Published: February 2015

It can be found that widely orthant dependent (WOD) random variables are
weaker than extended negatively orthant dependent (END) random variables,
while END random variables are weaker than negatively orthant dependent (NOD)
and negatively associated (NA) random variables. In this paper, we
investigate the Bahadur representation of sample quantiles based on WOD
sequences. Our results extend the corresponding ones of Ling [N.X. Ling, The
Bahadur representation for sample quantiles under negatively associated
sequence, Statistics and Probability Letters 78(16) (2008), 2660-2663], Xu et
al. [S.F. Xu, L. Ge, Y. Miao, On the Bahadur representation of sample
quantiles and order statistics for NA sequences, Journal of the Korean
Statistical Society 42(1) (2013), 1-7] and Li et al. [X.Q. Li, W.Z. Yang,
S.H. Hu, X.J. Wang, The Bahadur representation for sample quantile under NOD
sequence, Journal of Nonparametric Statistics 23(1) (2011), 59-65] for the
case of NA sequences or NOD sequences.
New type of generalized difference sequence space of non-absolute type and some matrix transformations
Authors: Mursaleen M. , Ganie Ab. , Sheikh Neyaz
Published: February 2015

In the present paper, we introduce a new difference sequence space rqB(u,p)
by using the Riesz mean and the B-difference matrix. We show rqB(u,p) is a
complete linear metric space and is linearly isomorphic to the space l(p). We
have also computed its ?-, ?- and ?-duals. Furthermore, we have constructed
the basis of rqB(u,p) and characterize a matrix class (rqB(u, p), l?).
Moment inequality of the minimum for nonnegative negatively orthant dependent random variables
Authors: Wang Xuejun , Wang Shijie , Hu Shuhe
Published: February 2015

Let {xn,n ? 1} be a sequence of positive numbers and {?n,n ? 1} be a sequence
of nonnegative negatively orthant dependent (NOD) random variables satisfying
certain distribution conditions. An exponential inequality for the minimum
min1?i?n xi?i is given. In addition, the moment inequalities of the minimum
(Ek - min1?i?n|xi?i|p)1/p for nonnegative negatively orthant dependent
random variables are established, where p > 0 and k = 1,2,..., n. Our results
generalize the corresponding ones for independent random variables to the
case of negatively orthant dependent random variables.
Fixed point results for Ciric typeweak contraction in metric spaces with applications to partial metric spaces
Authors: Choudhury Binayak , Kundu A. , Metiya N.
Published: February 2015

Partial metric spaces are generalizations of metric spaces which allow for
non-zero self-distances. The need for such a definition was felt in the
domain of computer science. Fixed point theory has rapidly developed on this
space in recent times. Here we define a Ciric type weak contraction
mapping with the help of discontinuous control functions and show that in a
complete metric space such a function has a fixed point. Our main result has
several corollaries and is supported with examples. One of the examples
shows that the corollaries are properly contained in the theorem. We give
applications of our results in partial metric spaces.
Detection of Insulitis by Pancreatic Scintigraphy With 99mTc-Labeled IL-2 and MRI in Patients With LADA (Action LADA 10)
Authors: Signore Alberto , Capriotti Gabriela , Chianelli Marco , Bonanno Elena , Galli Filippo , Catalano Carlo , Quintero Ana M. , De Toma Giorgio , Manfrini Silvia , Pozzilli Paolo ,   the Action LADA Group
Published: February 2015

OBJECTIVE

Pancreatic scintigraphy with interleukin-2 radiolabeled with 99mTc (99mTc-IL-2) is a technique used to image chronic inflammatory-mediated disorders. We used this method to detect a signal consistent with the presence of insulitis in patients with autoimmune diabetes. Positive and negative controls (patients with pancreatic carcinoma and type 2 diabetes, respectively) also were studied.

RESEARCH DESIGN AND METHODS

We examined 25 patients with autoimmune diabetes (16 with recently diagnosed type 1 diabetes, 9 with latent autoimmune diabetes in adults [LADA]), 6 with type 2 diabetes, and 7 with pancreatic carcinoma (the latter two groups were used as negative and positive controls, respectively). All patients underwent 99mTc-IL-2 scintigraphy and contrast-enhanced MRI of the pancreas. To validate positive controls, samples were taken from patients with pancreatic carcinoma during surgery for histological and immunohistochemical investigations.

RESULTS

Pancreatic accumulation of 99mTc-IL-2 was detected in patients with autoimmune diabetes (61% positive) and, notably, in 6 of 9 patients with LADA; semiquantitative evaluation of pancreatic uptake of 99mTc-IL-2 showed higher values in patients with autoimmune diabetes (both childhood and LADA) and pancreatic carcinoma than in those with type 2 diabetes (4.45 ± 1.99, 4.79 ± 1.1, and 4.54 ± 1.62 vs. 2.81 ± 0.63; P = 0.06, P = 0.01, and P = 0.04, respectively). In patients with pancreatic carcinoma, pancreatic interleukin-2 receptor expression correlated with pancreatic 99mTc-IL-2 uptake (r = 0.8; P = 0.01). In patients with LADA, 99mTc-IL-2 uptake inversely correlated with duration of disease (r = 0.7; P = 0.03).

CONCLUSIONS

Autoimmune diabetes in adults is associated with increased pancreatic 99mTc-IL-2 uptake, indicating the presence of insulitis, particularly within 1 year of the beginning of insulin therapy, similar to type 1 diabetes at diagnosis.
Predictors of Lower-Extremity Amputation in Patients With an Infected Diabetic Foot Ulcer
Authors: Pickwell Kristy , Siersma Volkert , Kars Marleen , Apelqvist Jan , Bakker Karel , Edmonds Michael , Holstein Per , Jirkovská Alexandra , Jude Edward , Mauricio Didac , Piaggesi Alberto , Ragnarson Tennvall Gunnel , Reike Heinrich , Spraul Maximilian , Uccioli Luigi , Urbancic Vilma , van Acker Kristien , van Baal Jeff , Schaper Nicolaas
Published: February 2015

OBJECTIVE

Infection commonly complicates diabetic foot ulcers and is associated with a poor outcome. In a cohort of individuals with an infected diabetic foot ulcer, we aimed to determine independent predictors of lower-extremity amputation and the predictive value for amputation of the International Working Group on the Diabetic Foot (IWGDF) classification system and to develop a risk score for predicting amputation.

RESEARCH DESIGN AND METHODS

We prospectively studied 575 patients with an infected diabetic foot ulcer presenting to 1 of 14 diabetic foot clinics in 10 European countries.

RESULTS

Among these patients, 159 (28%) underwent an amputation. Independent risk factors for amputation were as follows: periwound edema, foul smell, (non)purulent exudate, deep ulcer, positive probe-to-bone test, pretibial edema, fever, and elevated C-reactive protein. Increasing IWGDF severity of infection also independently predicted amputation. We developed a risk score for any amputation and for amputations excluding the lesser toes (including the variables sex, pain on palpation, periwound edema, ulcer size, ulcer depth, and peripheral arterial disease) that predicted amputation better than the IWGDF system (area under the ROC curves 0.80, 0.78, and 0.67, respectively).

CONCLUSIONS

For individuals with an infected diabetic foot ulcer, we identified independent predictors of amputation, validated the prognostic value of the IWGDF classification system, and developed a new risk score for amputation that can be readily used in daily clinical practice. Our risk score may have better prognostic accuracy than the IWGDF system, the only currently available system, but our findings need to be validated in other cohorts.