bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Horizontal and Complex-Trajectory Wells (November 2009)
Authors: Conran Greg
Published: February 2015

Technology Focus

The past year has experienced dramatic changes in industry activities. Despite the downturn, it has been encouraging to see that there has remained an active interest through various industry events and discussions in improvement in the delivery of complex wells.

I had the opportunity to participate in several SPE Advanced Technology Workshops (ATWs) and Forums related to this topic, and it was great to see record attendances, which provided for a diverse, yet high-quality, discussion and interaction. Design factors, improving drilling execution, and complex-well design, along with maximizing reservoir contact for horizontal and complex wells, are still major industry drivers, even though the industry has already drilled and completed many thousands of these wells.

Every year, new technology enters the market place providing potential for improvement of all aspects of horizontal-well operations, but on the basis of excellent and open discussions at SPE events, there still are further challenges to overcome. Conclusions from several meetings included positive reactions to the introduction of new technologies in helping drive performance to new levels, but it was highlighted that the repeatability depended upon good knowledge capture and transfer of learning.

Development of the structured approach, focused on continuous improvement, is as relevant today as it was 20 years ago. This message was echoed at all ATWs and Forums. The reduction in nonproductive time and overcoming operational challenges through better planning, although well known, are still a required focus.

As the industry adapts to a constantly evolving horizontal- and complex-well environment, positional accuracy and placement of the well trajectory are critical to better reservoir contact and production.

One interesting conclusion was that the successful drilling of many highly challenging wells appears to have been taken for granted. However, delivering the completion phase on long-stepout wells and management of the reservoir remain challenges for the future.

Horizontal and Complex-Trajectory Wells additional reading available at OnePetro: www.onepetro.org

SPE 118809 • "Beyond the Technical Limit: Turbodrilling—A Paradigm Shift to World-Class Horizontal-Well Construction" by Todd Mushovic, BP plc, et al.

SPE 119599 • "Inflow-Control Device: An Innovative Completion Solution From Extended Wellbore to Extended Well Life Cycle" by Saif Ali Al Arfi, ADCO, et al.

SPE 120579 • "A Comparison Between Multifractured Horizontal and Fishbone Wells for Development of Low-Permeability Fields" by Xiance Yu, University of Louisiana at Lafayette, et al.

SPE 123008 • "First Applications of Inflow-Control Devices (ICDs) in Openhole Horizontal Wells in Block 15, Ecuador" by P. Roman, Petroamazonas, et al.

OTC 19910 • "The Longest Challenge: Overview of a Groundbreaking Horizontal Well in Gimboa Field, Angola" by K.D. Contreiras, Sonangol Pesquisa & Produção, et al.
Continuous Improvement Led to the Longest Horizontal Well
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119506, "How Continuous Improvement Led to the Longest Horizontal Well in the World," by Kumud Sonowal and Bjarne Bennetzen, Mærsk Oil Qatar A/S; Patrick Wong, K&M Technology Group; and Erhan Isevcan, Schlumberger, prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17–19 March. The paper has not been peer reviewed.

In May 2008, Mærsk Oil Qatar completed drilling its Well BD-04A with a horizontal length of 35,770 ft. It was reported that this well set records for both the longest well, at 40,320 ft measured depth from the rotary table (MDRT), and the longest along-hole departure of 37,956 ft. The use of new techniques allowed existing constraints to be challenged and overcome successfully. These achievements were possible by applying sound engineering principles and continuous optimization during the field-development phases. Even when constrained by limitations, such as rig capacity, major step changes were achieved by optimizing basic operating parameters.

Introduction

The Al-Shaheen field is approximately 80 km northeast of the Qatar peninsula, Block 5 in Fig. 1. The Kharaib formation is a laterally uniform carbonate deposition generally 80 ft thick and has a reservoir target of approximately 25 ft. The Shuaiba formation exhibits lateral facies changes and permeability contrasts. Its thickness generally is 200 ft, with a reservoir target of approximately 20 ft. The Nahr Umr formation is a 20-ft sand sequence with reservoir targets of 5 ft of permeable sand or less.

The decision to develop this field by use of long-reach horizontal wells was driven primarily by the large aerial extent of the accumulation, poor productivity of vertical wells, and the number of platform locations required if a conventional approach with vertical or slant wells was pursued. The length of these horizontal wells has been extended during the course of the development, and some of these wells are pushing the limit that can be achieved with today's technology. To further enhance oil recovery from the Al-Shaheen field, it was decided, in 2007, to drill even longer wells and initiate measures with detailed engineering analysis to expand the horizontal extended-reach-drilling (ERD) envelope beyond industry experience.

Well BD-04A

At 40,320 ft MDRT, Well BD-04A was the longest well drilled, achieving the longest reach of 36,238 ft. The horizontal section was 35,770 ft [i.e., from the first survey with inclination above 86.0° at 4,550 ft MDRT to total depth (TD) at 40,320 ft], with 35,449 ft of continuous reservoir exposure.
Downhole Gas Compression: A New Artificial-Lifting System for Gas Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 121815, "Downhole Gas Compression: World's First Installation of a New Artificial-Lifting System for Gas Wells," by M.T. Di Tullio, SPE, S. Fornasari, and D. Ravaglia, Eni SpA E&P Division, and N. Bernatt, SPE, and J.E.N. Liley, SPE, Corac Group plc, originally prepared for the 2009 SPE EUROPEC/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed.

Downhole gas compression (DGC) is a new artificial-lift technology designed specifically for natural-gas wells and is an as yet unrealized opportunity within the upstream gas industry. The technology offers the opportunity to increase production by 30 to 50%, improve reserves significantly, and delay the onset of liquid loading. Although it can be used at any time during the life cycle of a gas asset, it will find particular favor during the decline phase.

Introduction

The upstream gas industry often is faced with the challenge of selecting an optimum artificial-lift system from various alternatives available for gas-well production enhancement. These challenges become more complex with increasing dynamic changes in well flow characteristics over the life of the well.

Application of DGC technology in suitable wells offers value for the following reasons.Acceleration of early production and extension of production plateau in new gas developments.Cost-effective rejuvenation of mature gas reservoirs characterized by low reservoir pressure and liquid accumulation in wells.Improvement of gas-well production and maximization of recovery factor from gas reservoirs with low environmental impact.Identification of incremental reserves and for monetization of stranded gas.

As part of an ongoing development through a joint-industry program, the first field trial of the new technology was conducted in an onshore gas well. The program has been completed in phases, including the design, building, and testing in a full-scale flow loop that closely replicated downhole conditions. The prototype has been tailored to suit the expected gas-flow range, composition, and condition of the selected field-trial well. Fig. 1 shows an internal view of one of the three compressor modules, with the gas path indicated in red.

Why Compress Gas Downhole

Operators of a producing asset always are seeking to maximize its value. In natural-gas fields, optimum gas production at low intervention cost and frequency is the ultimate objective in gas-well production management. To maximize production, the flowing bottomhole pressure (FBHP) should be kept as low as operationally possible. There are many challenges to achieving this objective.
Comments (December 2004)
Authors: Donnelly John
Published: February 2015

Editor's column - No abstract available.
Q&A with Chakib Sbiti
Authors: Sbiti Chakib , Donnelly John
Published: February 2015

Q&A - No abstract available.
Business Program Management for the Digital Oil Field
Authors: Holland Dutch , Skarke Gary
Published: February 2015

Management - No abstract available.
Overview: Bit Technology (December 2004)
Authors: Curry David
Published: February 2015

Overview - No abstract available.
Extending the Boundaries of Casing Drilling
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87998, "Extending the Boundaries of Casing Drilling," by A.M. Fisher, SPE, Brunei Shell Petroleum, and D.A. Reid, M.Z. Tan, and G.G. Galloway, SPE, Weatherford Intl., prepared for the 2004 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Kuala Lumpur, 13-15 September.
Laboratory Testing and Bit Dynamics Simulation Improves Drilling Performance in Chalk Reservoirs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87101, "Rock-Mechanics Lab Testing and Computerized Simulation of Bit Dynamics Improves Drilling Performance in Horizontal Chalk Reservoirs," by S. Gillick, SPE, Maersk Oil and Gas A/S, and R. Hamilton, SPE, A. Singh, SPE, and A. van der Pouw Kraan, SPE, Smith Bits, prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.
Overview: Production/Facilities (December 2004)
Authors: Richards Simon W.
Published: February 2015

Overview - No abstract available.
Pipelines in a Harsh Environment
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 16557, "Pipelines in Harsh Environment," by Anders Henriksson, Asbjorn Wilhelmsen, and Tor Karlsen, SPE, Norsk Hydro ASA, prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
Offshore Processing Options for Oil Platforms
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90325, "Offshore Processing Options for Oil Platforms," by Mark Bothamley, SPE, John M. Campbell and Co., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Transportation of High-Pour-Point Oil Through a Long, Hilly-Terrain Pipeline
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86929, "Transportation of High-Pour-Point Oil Through Long Hilly-Terrain Pipeline, A Case Study in Kalimantan, Indonesia," by Satya A. Putra, SPE, and Edo Waspodo, SPE, Pertamina, prepared for the 2004 SPE International Thermal Operations and Heavy Oil Symposium and Western Regional Meeting, Bakersfield, California, 16-18 March.
Overview: Reservoir/Asset Management (December 2004)
Authors: Hafez Hafez H.
Published: February 2015

Overview - No abstract available.
Stand Tall and Speak Up (December 2005)
Authors: Sprunt Eve S.
Published: February 2015

As SPE members we have a lot to be happy about. Our Society is thriving. Our membership is approaching 65,000, which includes some 14,000 students, thanks in large part to Halliburton’s generous sponsorship of student dues. Also, 2005 SPE President Giovanni Paccaloni’s passion for young professionals has created many new programs to entice new graduates to take advantage of the low membership fees for those under the age of 30. Moreover, we are an increasingly global Society, with over half of our members outside the U.S., 156 sections in 62 countries, members in more than 100 countries, and 131 student sections in 42 countries. Our eLibrary contains more than 40,000 papers. Together we have accomplished a lot, but that doesn’t mean we should rest on our laurels.

To better serve our membership, the SPE Board of Directors, past SPE Presidents, and other leaders of our Society have worked together to draft a new 10-year plan for the period 2005–15.

In the past, four Long Range Plans have been created, covering proposed strategies, tac-tics, and activities to guide the Society forward. The plans have covered the periods 1975–85, 1982–92, 1991–2000 (adopted in 1994), and 2000–10. These plans have played a major role in making SPE the financially sound, technically robust, and internationally respected and valued organization it is today. A long-range plan guides and focuses individual decisions by placing them in the framework of long-term goals. A plan also channels the energy and resources of the Society’s members and staff into addressing the highest priority goals.

Our industry is faced with many challenges, including the “big crew change,” the constant pressures of a commodity business to accomplish more with fewer people, rapidly changing technology, and a public that both worries that the world is running out of oil and fears that continued use of fossil fuels will create an environmental disaster. SPE’s Long Range Plan must simultaneously address all of these issues. Let me share with you some of the things in the plan that I think are most important.

Programs to attract young people to the industry and to train and retain young members.

Programs about reserves definitions and classifications for industry experts, nonexperts in the industry, and the public, including investors, to build support for new reserves and resources standards and to improve public understanding of the future of our industry.
Shortened Modeling Time Seen With Suite Concept in Reservoir Sampling
Authors: JPT staff _
Published: February 2015

Wireline-testing-tool capabilities and efficiencies are dramatically changing the value of formation-sampling and -testing programs. As real-time pressure-volume-temperature (PVT) simulation and collected formation samples are obtained closer to in-situ conditions, the accurate determination of produced-fluid composition is affecting project cycle times and reducing developmental risks, offering a narrow window of opportunity for operators to improve cost-efficiency.

While the value of formation characterization and samples remains in identifying the production potential of targeted reservoirs and design and development of production facilities, sampling is also an effective means of identifying water aquifers that require isolation during completion and confirming gas/oil/water contacts. In the past, it has been necessary for engineers to first understand the reservoir’s characterization and sampling needs, then define the proper tools or services, and finally to locate compatible tools.

Replacing traditional drillstem tests with a combination service portfolio that includes a wireline single-phase sampling program, real-time PVT predictions, and real-time contamination monitoring can potentially improve the accuracy of reservoir data and the quality of fluid samples and have a beneficial impact on essential design needs. Accurate determination of produced-fluid phase behavior and composition are valuable data used in designing completions, production facilities, and flow-assurance programs.

A combination service package, RESolution, was recently launched by Baker Atlas and consists of reservoir-fluid characterization, testing, and sampling services that provide real-time reservoir pressures, in-situ fluid samples, and fluid characterization. The portfolio service uses one logging instrument, the RCI Reservoir Characterization Instrument, with single-phase tanks that gather fluid samples downhole and then overpressure them to preserve the samples at in-situ conditions. By creating a state of overpressure before bringing the sample to the surface, the typical loss of pressure and cooling effect during the journey out of the wellbore results in retrieval of the sample at reservoir conditions.
Overview: Production/Facilities (December 2005)
Authors: Richards Simon W.
Published: February 2015

This year’s selection of papers is a mixed bunch that I thought would appeal to a wide audience. I deliberately chose papers to encourage as many as possible to read them. The broad theme is environment and sustainability. We have a duty to limit gas flaring as much as practicable to limit emissions and conserve fuel. A little-known effect of excessive flaring is addressed in the first paper. It’s a common saying that oil and water don’t mix. Well, the truth

is that sometimes they do. The food-processing industry spends a lot of time mixing oils and water that they sell us as food. However, in this industry, our problem is often finding ways to separate oil and water. No two sets of oil and water are the same, and the second paper looks at experiences in a Saudi Arabian field.

As our supply of high-quality light sweet crude oil is depleted, we start to produce the heavier sour grades of crude oil around the world. One of the problems with these fields is disposal of the large quantities of elemental sulfur that are recovered during the processing. Until now, it has often been stockpiled with, in my view, huge safety and environmental risks. Our third paper presents some novel means to dispose of this sulfur.

Our final paper deals with the end time for a production facility. Whether onshore or offshore, the production and processing facilities must be removed in accordance with local regulations. This task is clearly more difficult offshore, and this paper explains how it was handled offshore California.

I hope that you enjoy reading them as much as I enjoyed choosing them.

Available from the SPE eLibrary: www.spe.org

SPE 93653 “ExxonMobil’s Advanced Gas-to-Liquids Technology—AGC-21,” by R.A. Fiato, ExxonMobil Research and Engineering Co., et al.

SPE 93817 “Restoring Integrity to Aged Petroleum Production Facilities,” by S.W. Ciaraldi, BP Indonesia, et al.

SPE 96403 “Turning a North Sea Oil Giant Into a Gas Field—Depressurization of the Statfjord Field,” by R. Boge, SPE, Statoil, et al.

SPE 96504 “Canopy Bridges Along a Rainforest Pipeline in Ecuador,” by M. Thurber, SPE, Walsh, et al.
New PDC Technology Delivers Significant Savings in Oman
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 97340, “An Alternate Approach: Utilizing New PDC Technology for Drilling Deep LNG Wells Delivers Significant Savings for Major Operator in Oman,” by P. Teasdale, SPE, N. Riley, and P. Mackinnon, ReedHycalog, prepared for the 2005 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Dubai, UAE, 12–14 September.

A major operator has been drilling deep gas wells for several years in central Oman. These wells are drilled vertically through a complex geological sequence that provides a significant challenge to bit performance. Historically, these wells have been drilled in 90 days with tungsten-carbide-insert (TCI) bits on packed rotary assemblies to the 9⅝-in. casing shoe and diamond-impregnated bits on turbine assemblies with occasional TCI-bit runs in the 8⅜-in. section. A detailed study of the wells focused on optimizing drilling performance in each of the three hole sizes in a typical well profile. The findings suggested that the introduction of new polycrystalline-diamond compact (PDC) -bit technology was viable over much of the intervals and that significant savings in terms of time and cost could be achieved.

Trial Well 1

The initial trial well began in August 2003. Performance had been benchmarked and objectives were established for each hole section.

Top 17½-in. Hole. The following objectives were agreed upon.

- Complete 950-m interval in single run.

- Rate of penetration (ROP) greater than 14-m/h benchmark.

A premium Intl. Assn. of Drilling Contractors (IADC) code 415 TCI bit with a total flow area (TFA) of 7.19 cm2 was run on a rotary pendulum assembly with a single stabilizer positioned 27 m above the bit. The TCI bit features an extremely durable roller bearing for extended life and an optimized geometric hydraulic design with precisely angled nozzles to prevent bit balling and increase ROP.

The section was completed in 14 days compared to the planned 6 days, with 6½ days of lost time spent curing losses. A total of 16 trips and 9 bit runs was required to complete the interval because of hole problems. The 415-type bit drilled the 944-m interval as planned with an average ROP of 13.2 m/h that was slightly lower than the 14-m/h target established before the run. At surface, the bit was balled up but in good condition and was graded 2-2-CT-A-E-I-NO-TD. Consideration of the controlled parameters applied in the upper section to minimize the risk of losses, and the excellent performance achieved in the lower section where flow rates were optimized and ROP increased to more than 20 m/h demonstrated the potential for better performance in this section.
Heavy Oil, Reserves, Industry Challenges Highlight ATCE
Authors: JPT staff _
Published: February 2015

Panel discussions on heavy oil technology, reserves classification, and changing industry demographics highlighted the 2006 SPE Annual Technical Conference and Exhibition ((ATCE) in San Antonio. More than 500 technical papers on innovative technologies, case studies, and best practices, along with an exhibition showcasing more than 400 companies, rounded out the event, which attracted approximately 99,300 industry professionals.

The opening general session featured a wide-ranging discussion on a topic that high oil prices and rising global demand have pushed into the spotlight. "Heavy Oil—From Rock Face to Fuel Pumps" featured Vikram Rao, Vice President of Technology for Halliburton Energy Services; Robert Skinner, former Director of the Oxford Inst. for Energy Studies; Murray Smith, Minister-Counselor of the Government of Alberta, Canada; Sylvestre Calmon, Manager of Refining Technology at Brazil state oil company Petrobras; and Don Paul, Vice President and Chief Technology Officer for Chevron.

Although heavy oil shows great promise to help satisfy growing global demand, its development is not without significant technical, financial, and environmental challenges, the panelists agreed. Panel moderator Rao noted that, unlike conventional oil production, heavy oil has closer links with lifting, transporting, and refining, which makes its development more complicated. Heavy oil is difficult to move, requires sophisticated refinery configurations for processing into consumer end products, and produces CO2 emissions.

Skinner said that companies are putting more money into heavy oil development, especially in western Canada, because there is little geological risk, there are long-term predictable growth rates, there is a technology upside, and the projects are winning approval from financial markets. "But it's not all a rosy picture" in the Canadian oil sands, he said, because of the shortage of both technical and general labor, the high capital expenditure involved, and the operational risks of working in a northern environment. Venezuela's Orinoco belt actually offers better economics for heavy-oil production, but political risk deters investment there, he said.

Offering a resource owner's point of view, Smith said he believes Canadian oil production may grow faster than OPEC output in the near future and will play an increasingly important role in meeting U.S. energy consumption. "Alberta will contribute significantly to U.S. imports over the next 20 years," he said. Oil-sands reserves total 174 billion bbl, of which approximately 20% are recoverable by mining and 80% by steam-assisted gravity drainage, he added. Western Canada is definitely experiencing the strain of increased activity and needs pipeline expansion, new refineries, retrofitting of existing refineries, and a larger labor pool. "We are really feeling the pinch of not training enough professionals" from the mid-1980s on, he said of the oil and gas industry.
Preparing a Business Case for Technology Investment in Production Operations
Authors: Hite J. Roger , Farid Kemal , Blanton M. Lee , Gard Fred , Crawley Charles
Published: February 2015

Broad support exists in the leadership of most large oil and gas companies for a version of the digital oil field as a strategic direction, but there is difficulty at the implementation level in building a convincing case for investment. Implementation seems slow, perhaps because generating a convincing business case for incremental investment is challenging.

Winning acceptance for new computing, automation, and communications technology* (CACT) in the oil patch is always a challenge, and one that begins and ends with a convincing business case. A good business case speaks to decision makers in a language they understand. It outlines in clear terms the benefits of the investment, its costs, and its risks. Each needs to be presented clearly, openly, and honestly.

A good business case is guided by five principles:Value is created only when good decisions are made and implemented. The value of an oil and gas asset derives from decisions made and implemented in the past—to drill wells, to complete them, to implement recovery processes, and to install facilities. Once decisions and investments are made, the assets are operated in a way to capture the intended value.

Oil fields do not exactly run themselves, of course, because numerous decisions are made every day to keep them running smoothly. Lift changes, new choke settings, changes in injection and production rates, and set-point adjustments are all designed to make sure the value of the original investment is achieved. Added value is created when decisions are made and implemented to add new assets, modify existing ones, or to change operating practices or procedures. It is important that these decisions be the right decisions made at the right time. Whether they are depends greatly on the quality of the information avail-able at the time.CACT investments affect decisions. Computers do not produce oil; they facilitate decisions. Thus, the value of investments in CACT derives from its ability to improve decision making or improve on the decisions that are made. Having more terabytes of data stored on a server does not help a bit. Rather, it adds cost. Likewise, storing production rates and pressures minute by minute does not add value. Faster communications, bigger computers, and more gadgets do not help unless they lead to better or more timely decisions.Real time is defined by the frequency of decisions that need to be made. Because the value of CACT investments comes from the decisions it influences, the frequency of data collection should be matched to the rate at which decisions can be made and implemented safely. The decision rate defines what "real time" really is. Information at time scales shorter than the rate at which decisions are made does not help because the information cannot be acted on that fast. Longer time scales may mean lost opportunities because decisions could be made faster if the information were there. Thus, "real time" is really "right time"—the right time for making decisions.
Overview: Production/Facilities (December 2006)
Authors: Richards Simon
Published: February 2015

Welcome back to the Production/Facilities feature. This issue focuses on environmental and corrosion challenges. These challenges are especially important because the global production infrastructure is aging, with much of it more than 30 years old. These issues are, of course, intertwined because the materials and corrosion engineer spends much of his/her time preventing the produced fluids from escaping into the environment. This issue delves into new or revitalized developments in produced-water treatment. Concern has been mounting over the years regarding the effect on the environment of chemical treatments used by the industry when the chemicals are discharged with produced water, for example. New "green" corrosion inhibitors have been developed.

As well as preventing corrosion in susceptible materials, the materials and corrosion engineer also must be able to assess the effect of any corrosion that has occurred. State-of-the-art calculation of the corrosion rate is available. Also, a new approach has been developed to assess the internal condition of a pipeline accurately.

A low-cost water-purification treatment has been used in the sewage-treatment industry for many decades. It is being transferred to the petroleum industry. The use of reed beds is common as an alternative waste water treatment in remote areas. This method is being used in the Nimr field, onshore Oman. Essentially, the reeds capture the impurities through the root system, where they are held in the plant tissue. The plants then can be harvested and used as biomass fuel, for example, and the residual ash, which contains the inorganic impurities, can be disposed of safely.

Production/Facilities additional reading available at the SPE eLibrary: www.spe.org

SPE 100673 "Assessment and Comparison of CO2-Corrosion Prediction Models" by R.C. Woollam, BP plc, et al.

SPE 98854 "The Path to Zero Flaring in Zadco" by M.M. Misellati, Zadco, et al.

SPE 100412 "Prediction Equation of CO2 Corrosion With the Presence of Acetic Acid" by M.C. Ismail, U. Teknologi Petronas, et al.

SPE 103922 "Internal-Corrosion Direct Assessment for Multiphase-Flow Pipeline Systems" by P.G. Puente, SPE, Scandpower PT, et al.

IPTC 10548 "Produced-Water-Management Strategy Water-Injection Best Practices—Design, Performance, Monitoring" by A.S. Abou-Sayed, Advantek Intl. Corp., et al.
An Alternative Approach To Evaluate Internal Pipeline Condition
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100727, "Alternative Approach to Internal-Pipeline-Condition Assessment," by K.E. Oliver, D.G. John, and A. Crossland, CAPCIS Ltd., prepared for the 2006 SPE International Oilfield Corrosion Symposium, Aberdeen, 30 May.

The full-length paper details an uncertainty-based probabilistic approach to determine the internal corrosion condition of a pipeline under varying operating conditions. This approach allows the risks associated with future maintenance options to be quantified.

Introduction

Pipeline-integrity management is becoming increasingly important to the oil- and gas-production sector. Tiebacks from marginal fields into existing pipelines result in aging pipelines being operated well beyond their original design life. New pipelines also are being constructed in increasingly challenging environments. All of these factors introduce greater uncertainty into prediction of future pipeline integrity. In-line pipeline inspection is expensive, but modeling of pipeline operating conditions can provide an estimate of metal loss when no detailed inspection data exist.

Historically, engineers have used conservative values when there were uncertainties about parameter values. These assumptions result in a worst-case output that may result in the pipeline being condemned. Developing a means to incorporate these uncertainties into corrosion-prediction tools allows a more accurate determination of risk and a better selection of control programs.

Uncertainty Modeling

A distribution of values is constructed for each uncertain variable used to calculate likelihood of failure. A number of different results can be compared for different operating scenarios. The risk of failure can be described in terms of probability of pipeline failure on a year-by-year basis for the scenarios.

Input-data uncertainties are described by a statistical distribution that is defined on the basis of operating data collected from the field. Current conditions can be assigned a distribution on the basis of the range of defects measured during an intelligent-pig or other inspection. Laboratory-test data can be used to assign corrosion-inhibitor efficiencies. Where there are no data, field knowledge can be used to assign a credible value range.

The distribution shape is based on the conditions surrounding the variable and therefore specific to the parameter in question. Typical distributions used include the following.Truncated normal distribution used for general-corrosion distribution.Log normal distribution used for pitting-corrosion defects.Triangular distributions used for inhibitor effectiveness and availability.Uniform distributions used for pressure.Minimum extreme distributions used for temperature under rapid-cooling conditions.

The distribution can be embedded in a standard corrosion-rate or metal-loss calculation by use of a Monte Carlo simulation that randomly generates values for the uncertain variable.
Overview: Reserves/Asset Management (December 2006)
Authors: Rietz Dean
Published: February 2015

Looking through the abstracts of approximately 65 papers, and needing to select relevant papers for this feature, proved the following to me.My selections will leave some important and useful papers "behind."There is a wealth of experience to be shared among SPE members worldwide.The topic of risk and dealing with uncertainty continues to be a major theme—as well it should, because it is what we do on a daily basis as petroleum engineers.

To address my first issue, I simply tried to identify the papers that would have the broadest appeal to benefit the most readers. I would encourage you to search online (SPE's eLibrary) to find papers that are not listed here.

As for issue two, there were plenty of papers illustrating best practices or promising results and conclusions from case studies. Take note of the selected case studies, because the authors' experiences and observations can add to your repertoire of knowledge to improve the management of your own assets and projects, however different they may be from those highlighted.

As for risk and uncertainty, the selected papers help provide a better understanding of the topic by highlighting the latest developments and practices.

Finally, keep in mind that what we lack in experience (both successes and failures), we must make up for in terms of acquiring knowledge and risk/reward and uncertainty management. Our predecessors were able to conduct business based heavily on experience and the best understanding of the inherent uncertainties. This method may have been appropriate at that time, regardless of the project. Unfortunately, we have moved to the cutting edge of "mega scale" projects such as harsh environments or deep and ultradeep water that are so significant in terms of economic scale, human resources needed, and the complex interrelated components, that in some cases overall project management is almost beyond comprehension. Therefore, acquiring knowledge and understanding risk and uncertainty become as important as a lifetime of experience.

Reserves/Asset Management additional reading available at the SPE eLibrary: www.spe.org

SPE 97269 "Risk and Uncertainty Management—Best Practices and Misapplications for Cost and Schedule Estimates" by S.K. Peterson, SPE, J Murtha & Assocs., et al.

SPE 102505 "The Selection, Application, and Misapplication of Reservoir Analogs for the Estimation of Petroleum Reserves" by J.E. Hodgin, SPE, Ryder Scott Co., et al.

SPE 100607 "U.K. North Sea and Alaska North Slope: A Comparative Analysis of Petroleum Provinces" by J.A. Walker, SPE, ConocoPhillips Alaska Inc., et al.
Dynamic Economic Indicator To Evaluate SAGD Performance
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 100525, "A Dynamic Economic Indicator To Evaluate SAGD Performance," by H. Shin, SPE, Shell Canada Ltd., and M. Polikar, SPE, U. of Alberta, prepared for the 2006 SPE Western Regional Meeting, Anchorage, 8-10 May.

An economic indicator called simple thermal-efficiency parameter (STEP) was developed to evaluate the performance of a steam-assisted gravity-drainage (SAGD) project. A dynamic model called STEP-D was developed for use as an economic indicator under the changing conditions of the economic limit of the instantaneous steam/oil ratio (SOR) and the price of heavy oil.

Introduction

The economics of a SAGD project is related to several production-performance parameters. The most significant are SOR, cumulative steam/oil ratio (CSOR), ultimate recovery factor (RF), and project life. STEP is based on CSOR, calendar day oil rate (CDOR), and RF for the time corresponding to an SOR of 4.

STEP's usefulness as an economic indicator was validated qualitatively as well as quantitatively. STEP was introduced to optimize SAGD operating conditions in Athabasca-, Cold Lake-, and Peace River-type reservoirs in the Alberta oil sands. This economic indicator was modified to evaluate the performance of a SAGD project under selected reservoir parameters and optimal operating conditions. STEP was found to be a useful qualitative as well as quantitative economic indicator in evaluating SAGD performance.

In reality, the economics of a thermal project depends strongly on the economic limit of SOR and heavy-oil price, poil. These variable parameters are used in the economic evaluation of field projects. In this research, a dynamic model, STEP-D, was developed for use as an economic indicator under these changing conditions. For the STEP-D calculation, the economic limit of SOR was varied from 3 to 6 and the poil from U.S. $15 to $30/bbl for three oil-sands reservoirs in Alberta.

Development of a Dynamic Economic Indicator

Initially, STEP was used to evaluate the performance of a SAGD project under optimal conditions. It was pro-posed as a simple economic indicator, to be used instead of net present value (NPV), while determining the best SAGD operating conditions. The simulation results showed that NPV had a linear relationship with RF and CDOR, but a decreasing exponential relationship with CSOR.
Building Bridges: My Journey Begins…(December 2007)
Authors: Cobb Bill
Published: February 2015

As I begin my year as 2008 SPE President, I express my humble thanks for the opportunity to serve you and lead our Board of Directors. Also, I want to thank my friend and fellow Stanford alumnus, 2007 SPE President Jaleel Al-Khalifa, for the leadership, guidance, and direction he has given to the SPE for the past 12 months. Jaleel, you represented SPE very well; you reached the peak of Mt. Everest, climbing the trail you described in your September 2006 JPT interview. With your help, SPE's strong team of volunteers, our international Board of Directors, and our excellent staff, we will move forward to climb new heights.

As I indicated in my interview with John Donnelly in last month's JPT, one of my primary goals for the year is to give direction to the SPE Long Range Plan. The Long Range Plan guides the Board of Directors in developing SPE's programs and strategies. The plan is updated on a regular basis but its adoption by the Board of Directors occurs only after it is discussed and modified by a committee of diligent groups of SPE members.

I also said that I wanted to be an effective ambassador for SPE, which is reflected in the title I have chosen for my JPT column. As President, I want to build bridges and more effectively connect SPE to its members, industry, and the general public. Also, I want to stimulate a higher level of volunteerism among SPE members.

Much is going on in SPE's operations. The SPE has hired a new Managing Director for Middle East, India, and North Africa activities, Waleed Refaay. He is based in our Dubai office. We welcome Waleed to the SPE management team and look forward to working with him…. In October, SPE opened a new regional office in Moscow, which will fall under the management of Lawrence Slade, Managing Director Europe, Russia, and West Africa, in SPE's London office. The Moscow office will allow SPE to more effectively serve its members in Eastern Europe, Russia, and other countries in the region.

During my professional career, I have been able to travel to more than 40 countries. As a result, I can count personal friends on six continents (I may make it to Antarctica, but am not placing any bets on that). I look forward to reconnecting with many of them in the coming months and to making many new friends. With more than 70,000 SPE members out there, I have many potential connections to make.
Technology Update: Modeling H2S-Scavenger Efficiency Cuts Costs
Authors: JPT staff _
Published: February 2015

The problems associated with production of H2S are well defined within the oil industry, with the major issues related to safety, corrosion integrity, and production deferment. Shell now has at its disposal a software model to predict H2S-scavenger efficiency in an effort to reduce costs and optimize chemical treatment regimes. The company also has available a test flow loop for evaluating scavenger performance under a wide range of simulated field conditions.

Phase 2 of a joint-industry project (JIP) with the Chicago-based Gas Technology Institute (GTI), which Shell recently completed, provided the basis for the company's advances. The JIP work complements some extensive optimization work on a Shell field, where practical considerations to the chemical application had a proven significant effect on chemical use and subsequent reduction. This practical test work offshore clearly defined the many and varied considerations to the application technique required to achieve success. The results from one example are shown in Table 1.

Similar reductions in chemical use were noted for two other platforms in the field during this extensive off-shore optimization study. The main factor contributing to this reduction was the relocation of the injection point. Further cost reductions of approximately 15% are feasible with a high probability of success through implementation of the following:Improved monitoring and measurement of H2S in the export gas, which would allow optimization and control of the scavenger-dosage regime by up to 15%Improved delivery of chemical by priming the pulsation dampener and using an appropriately sized atomization nozzleMaximized contact between the injected chemical scavenger and the sour gas from the low-pressure compressor, through use of an additional scavenger-injection point at the high-pressure separator dischargeUse of a pump suitable for the volumetric injection ratesFitting the flowing system with a retrievable insertion probe for ease of maintenance and reduced downtime

Additional savings of more than 10% in chemical costs are achievable through automating the injection, with a payout period of less than 1 year projected for this.

Implementing the above recommendations will yield a positive environmental impact by achieving up to a 30% reduction in the concentration of unspent scavenger in the water that is discharged overboard.
Overview: Production/Facilities (December 2007)
Authors: Richards Simon
Published: February 2015

It does not seem a year since the last facilities feature. The theme this year is about heavy-oil upgrading to light oil; although a paper about wax seems to have slipped in too. Heavy oil is an enormous energy resource that still is largely untapped. The challenge is to get the stuff out of the ground as fast as the lighter oil that we currently produce. Unfortunately, the density and viscosity usually make this target very difficult in the end.

However, heavy oil is not all bad; on a volume basis, it contains more energy than lighter oil.

Currently, the industry is attempting to justify heavy-oil developments on two fronts: by developing new means for extracting it faster and by increasing its value. This is where the real prize is in heavy oil—its value. Its value currently is largely unrecognized; it sells often much cheaper than lighter oil even though it contains more energy on a volume basis. The industry is currently developing ways to upgrade it to light oil to add value; but there are other ways of adding value, and to find these, one must re-examine the business model of the upstream industry that has not changed in 150 years. We continue to produce and sell crude oil to refiners and let the oil traders set the price. We can, and should, be more proactive in finding ways to exploit the irreplaceable value of oil.

Production/Facilities additional reading available at the SPE eLibrary: www.spe.org

SPE 107958 "Modeling Rapid Multiphase Flow in Wells and Pipelines Under Nonequilibrium and Nonisothermal Conditions" by Guillermo Michel, University of Oklahoma, et al.

SPE 108752 "A Study of Normal Slug Flow in an Offshore Production Facility With a Large-Diameter Flowline" by E. Guzmán Vázquez, National Autonomous University of Mexico, et al.

SPE 104133 "Leak Detection for Gas and Liquid Pipelines by Transient Modeling" by Shouxi Wang, Gas Liquids Engineering, et al.
A Case Study in Wax Removal From a Subsea Flowline
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105048, "A Case Study in the Removal of Deposited Wax From a Major Subsea Flowline System in the Gannet Field," by H.A. Craddock, SPE, K. Mutch, and K. Sowerby, Roemex Ltd., and S. McGregor, J. Cook, and C. Strachan, Shell UK Ltd., prepared for the 2007 SPE International Symposium on Oilfield Chemistry, Houston, 28 February–2 March.

The following stages were key to the successful wax-removal operation: selection and design phase of the chemical application, the environmental chemical-selection criteria, the development of the work scope, and the logistics of the chemical application. The wax-removal process was deemed successful and offered the client significant benefit in terms of increased oil production. Reduced pipeline differential pressure and increased fluid arrival temperatures also indicated that the wax restrictions in the flowlines had been removed.

Introduction

The control and mitigation of wax deposition and its concurrent problems rapidly are becoming critical challenges facing the oil- and gas-production industry as the industry explores and develops in increasingly challenging environments, such as deepwater and subarctic conditions. Wax deposits can occur widely in the production process and often are considered the organic equivalent of scale formation.

Field Description

The Gannet field is 180 km east of Aberdeen in a water depth of approximately 90 m. Since the field was originally discovered, in the 1970s, several satellite fields have been tied into the Gannet facilities. Gannet D is an oil field 16 km northeast of Gannet Alpha. Production is from five wells, with oil transported back to the Gannet Alpha facilities by two looped 6-in. subsea flowlines referred to as Riser 31 and Riser 32. The crude from these reservoirs typically is 41°API, with a wax content of approximately 7% and a wax-appearance temperature of approximately 35.5°C. The Gannet G field also is produced by this system with a single 6-in. flowline tied in at the base of Riser 32, 0.5 km from the Gannet Alpha platform. Riser 31 carries Gannet D crude only, and Riser 32 carries Gannet D and G crude topside onto the Gannet Alpha processing facilities, where the oil is commingled with other Gannet fluids before being exported to the Fulmar platform.