bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Development of the Changbei Tight-Gas Project
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 11408, "Integrated Development of Changbei Tight Gas Project," by Guilin Luan, SPE, Lin Li, Gary Nettleship, SPE, Luc Van Son, and Taco Hoekstra, Shell China E&P; Robert Deutman and Sieward Veeman, Sarawak Shell Bhd.; and Hua Wang, PetroChina ChangQing Oilfield Co., originally prepared for the 2007 International Petroleum Technology Conference, Dubai, UAE, 4-6 December. The paper has not been peer reviewed.
Changbei is an onshore tight gas field in north Shaanxi Province, China. The main reservoir is a thin and fairly complex braided-channel sandstone formation with a 5% average porosity and a 0.7-md permeability. For field development, a dual-lateral well with two 2000-m horizontal sections was selected. After a summary of the development-concept selection and the status of the project, the full-length paper details some of the development challenges.

Introduction
A production-sharing contract (PSC) was signed between PetroChina and Shell in 1999 to develop the Changbei gas field, followed by a 2-year extensive evaluation and appraisal period to prepare a development plan. Appraisal activities performed included fracturing existing and newly drilled vertical wells and drilling/testing horizontal wells.
The Changbei tight-gas development is the largest onshore cooperative venture between an integrated oil company and one of the three Chinese oil majors in terms of investment and development scale. In addition to difficult reservoir conditions, challenges specific to the local environment had to be overcome [e.g., technology and equipment availability; local-contractor competence; community relations; and high health, safety, and environment (HSE) standards].

Field History
Exploration drilling in the Changbei Block began in 1991. The first small-scale gas production to supply the local community was recorded in 1995. Seismic was used to predict the lateral continuity of the reservoir-sand body and reservoir boundary, leading to an extensive exploration campaign during 1996–97, culminating in a successful well test. Two-hundred-fifty 2D-seismic lines with a 3800-km approximate length were acquired. Twenty exploration wells, nine development wells, and two appraisal wells were drilled before field-scale development planning and project execution. All wells were vertical except the two appraisal wells, where both vertical and horizontal sections were drilled. Basic well tests were conducted on most of the wells. Trial production on 16 wells began in November 1999, which provided valuable information on well/reservoir dynamic behavior and helped gain production experience with vertical and hydraulically fractured wells in the tight gas reservoir.
Conversations: Discover the Best in Yourself!
Authors: Fattahi Behrooz 
Published: February 2015

President's column
This is my first column for JPT. My promise to you is that my comments will always be short, so that you will take the time to read them, and that I will be clear and concise in conveying my thoughts to you. My comments will be intended to stimulate conversations with you. I hope that you also will initiate conversations, letting me know about things that are important to you. I need your engagement to make our conversations meaningful. Contact me by email at president@spe.org, or through the President's Forum on www.spe.org, and let me know what you think!
This month, I would like to talk about our professional society and the challenges it faces. In future months, I will elaborate on each of these challenges and offer ideas on how you can help meet those challenges. My message throughout the year will be to emphasize the critical need for each of us to contribute to the mission of the SPE, by getting involved. We represent many different backgrounds and technical disciplines, but we share a common mission—to discover and to learn. As members of our professional community of roughly 90,000, we should look around and find out how we can be relevant in this process. Ours is a member-driven society; without your involvement, we will not succeed.
For SPE, there are immense strategic challenges ahead. These challenges are global, multi-dimensional, complex, and interlaced. Failure in one will have detrimental effects on others.
Our Society is one of the most global professional societies in existence, with 170 sections in more than 66 countries. However, even with this global reach, the level of participation in SPE volunteer activities in some areas of the world is still fairly low. In our attempt to extend our reach, we face increasing challenges in adapting to the diversity in cultures, languages, habits, and geographical and political constraints.
Attracting young people to the industry, and addressing their needs while trying to engage our experienced workforce, will continue to be a hot topic for the years to come. It is estimated that as many as 50% of our experienced professionals will be eligible for retirement in the next 10 years. This is occurring at the same time that the demand for energy is expected to increase by 50% in the next 20 years. We all realize that the ability to make complex decisions and to exploit advanced technology requires years of on-the-job experience.
Another significant challenge for us is to maintain or improve the quality and integrity of our services and to deliver them to all of our members wherever they may be and at the highest possible quality. The diversity and the variation of our products, funding, and the logistics for timely delivery of these products to wide-ranging geographical locations demand a significant effort for the organization.
Technology Focus: Field Development Projects (October 2009)
Authors: Rebelo Mauricio P. 
Published: February 2015

Technology Focus
The increasing oil price over the past years, combined with the dwindling of new oil reserves in places with low exploration-and-production cost, has led oil companies to explore for oil in new frontiers. The industry is forced to face new and unknown difficulties. Among the challenges are ultradeep water, ultradeep wells, subsalt drilling, complex reservoirs, and increasing environmental risk, to mention just a few.
After achieving success in the exploratory phase with new discoveries, deciding to move into the development-and-production phase leads companies to face yet bigger challenges, such as developing fields that will need to use new technologies and making the development and production of these fields economically viable. Furthermore, some projects will have to deal with the unavailability of resources in the industry (i.e., rigs, new drilling/completion techniques and equipment, human resources, and others), as is often expected.
The projects presented in the following selected papers bring some of these issues to our attention. Each project, in a different area of the globe, has its own particularity and challenges, which require enormous effort on the part of oil industry as a whole. Oil companies and service companies jointly will have to continue working hard to make these projects become a new chapter in the success history of the oil industry.
Field Development Projects additional reading available at OnePetro: www.onepetro.org
OTC 19861 • "Tahiti Subsurface—Drilling- and Completion-Technology Challenges and Accomplishments" by Luis F. Rivas, Chevron, et al.
SPE 115367 • "Implementing i-field Initiatives in a Deepwater Green Field, Offshore Nigeria" by O.S. Adeyemi, SPE, Chevron, et al.
SPE 118840 • "Field-Development Optimization Applied to Giant Oil Fields" by Michael L. Litvak, BP plc, et al.
SPE 121680 • "Southern North Sea Tight-Gas-Field Development Planning Using Hydraulic Fracturing" by Bart Vos, Pinnacle Technologies, et al.
CO2 Applications - Discussion and Reply
Authors: Evans Ronald T. , Jenvey Nigel , Wehner T. Scott C. , Gomersall Sam 
Published: February 2015

Discussion and Reply
Editor's note: Several readers responded to the Technology Focus article on CO2 Applications written by Sam Gomersall, director of CO2DeepStore, that appeared in the July issue. Excerpts from some of those letters, along with a reply from the author, follow.

Discussion
Ronald T. Evans, SPE, Denbury Resources, writes:
In the Technology Focus article on CO2 Applications (July 2009 JPT, p. 68) the ultimate conclusion that "Enhanced oil recovery (EOR) … is not a CO2-abatement technique" fails to assess CO2 EOR accurately. CO2 EOR projects that use anthropogenic CO2 have the ability to sequester more CO2 than the oil produced will ultimately release. According to the US Department of Energy's National Energy Technology Laboratory (NETL), CO2-EOR projects sequester up to 70% of the CO2 that will ultimately be released by the oil. This report is based on west Texas, water-alternating-gas CO2 EOR projects that inject 5 to 6 Mcf of CO2 for each barrel of oil produced. The report discusses "Next-Generation CO2-EOR Technologies" that have the capacity to inject as much as 160% of the CO2 ultimately released by the oil.
Continuous-injection CO2-EOR projects inject 10 to 12 Mcf of CO2 to produce each barrel of oil. Continuous-injection CO2-EOR projects have the capacity to sequester significantly greater CO2 volumes than the oil releases when consumed.
Not only does CO2 EOR with anthropogenic CO2 have an important role to play in energy security, it is a significant CO2-abatement technique. It is the only carbon-capture/sequestration (CCS) method that can be conducted today, and it is the only CCS method that produces additional domestic energy and economic benefits while sequestering CO2. For additional reading material, please see:
CO2 Enhanced Oil Recovery. World Resources Institute, www.wri.org/publication/content/8355.
Tapping into Stranded Domestic Oil: Enhanced Oil Recovery with Carbon Dioxide is a Win-Win-Win. Natural Resources Defense Council, www.nrdc.org/energy/eor.pdf.
Storing CO2 with CO2 enhanced oil recovery. US National Energy Technology Laboratory, www.netl.doe.gov/energy-analyses/pubs/Storing%20 CO2%20w%20EOR_FINAL.pdf.
Interventionless Monobore Technology Used for Offshore Horizontal Gas-Injection Wells
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17458, “Interventionless Monobore Technology Used To Complete Challenging Offshore Horizontal Gas-Injection Wells Successfully,” by M.O. Etuhoko, SPE, P. Essel, and C. Terre, Total E&P–Elf Petroleum Nigeria, and L. Proctor, SPE, Halliburton Energy Services Inc., prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission.
Elf Petroleum Nigeria Ltd. is developing the Amenam/Kpono oil field on the Nigerian Continental Shelf in the eastern offshore Niger delta. The field development was extremely challenging, with high-reach departures of up to 2 miles. New technologies [e.g., reservoir drilling fluid, fluid-spring-operated valve, gravel-pack packer, tubing-tester flapper valve (TTFV), production packer, and permanent gauge] were integrated to satisfy all well needs, especially those of the challenging horizontal gas injectors.
Introduction
The first phase of the field development was for reservoirs R4, R9, R10, and R11 in the western and central parts of the field. Two drilling platforms, AMD1 and AMD2, were installed 345 ft apart and connected to a production platform (AMP1). The development involves drilling and completing 34 wells, of which 18 are oil producers, 5 are gas injectors, and 11 are water injectors. At the R4 reservoir level, gas injectors are required for pressure maintenance from initial production because the bubblepoint pressure is approximately equal to the reservoir pressure. A primary target in the developmental plan was to use enhanced completion equipment to reduce operational risks while completing as quickly as possible. A monobore-completion design with interventionless technology was chosen.
All wells were to be developed with interventionless technology, which would allow running and pressure testing the completion string as often as necessary without deploying a slickline. It also would allow setting the production packer without a slickline.
Well-Completion Design
A detailed design used software to deter-mine the tubing stresses and fluid-temperature profiles. The packer/tubing link would be standard for all wells. The value of the thermal derating factor used was 0.05%/°C. Because of the well pressure and temperature conditions, a premium-joint tubing connection was used in the tubing-stress simulations. The calculations were run with 100% efficiency for tension strength and 80% efficiency for compression strength. The values were designated to meet the following criteria.
Designing the Perfect Drilling-Fluid Additive: Can It Be Done?
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 95196, “Designing the Perfect Drilling-Fluid Additive: Can It Be Done?,” by J. Hall, SPE, Halliburton, prepared for the 2005 SPE Asia Pacific Health, Safety, and Environment Conference and Exhibition, Kuala Lumpur, 19–20 September.
The environmental effects and technical performance of drilling-fluid additives are important characteristics of these products, which at times seem to be at odds with each other. For example, materials that show good stability at high temperatures frequently do not biodegrade well. In addition to the paradox of performance vs. environmental acceptability, international drilling-fluid companies face diverse environmental regulations when operating in geographically distinct areas. The full-length paper discusses real-life examples of drilling chemicals that were designed to fit stringent environmental criteria, according to the areas where they were used.
Introduction
Use and discharge of drilling fluids and cut-tings during well-construction activities have occurred since the beginning of off-shore drilling. However, it was not until relatively recently that these discharges have been regulated. Some of the most active drilling regions in the world also contain important commercial fisheries. Where regulations have been established, government agencies have been charged with establishing a control system to ensure that long-term effects do not occur in areas where drilling and well-construction discharges take place. These control systems rely on a range of tools to predict, rank, or otherwise categorize the expected effect of discharged materials. There may be a heavy reliance on laboratory-based toxicity and biodegradation tests, or attempts to predict the potential for materials to bioaccumulate.
For example, it is easy to demonstrate that many organic materials will almost completely biodegrade when tested by a commonly used test to assess biodegradation in seawater. However, this is not much help in predicting when a base fluid discharged on cuttings will no longer be detected on the seafloor, or when the effects of a drilling-fluid spill will no longer be detected. The reasons for this are two-fold. First, the marine environment is a dynamic place, and materials dispersal can be rapid. Also, to obtain test results in a useful time frame, the conditions of testing may be idealized. For example, in the biodegradation test, the water oxygen content, test temperature, and nutrient mixture available to the bacteria present are optimized to produce a result in 28 days. In the natural environment, seafloor temperature may be as low as 2°C, and if the material is buried in a pile of drill cuttings, influx of nutrient-containing, oxygenated seawater may be severely limited so that degradation of the same materials showing good laboratory results may be reduced. However, the laboratory test provides the regulator an indication of the relative performance of a range of oilfield chemicals.
Petroleum Industry 2020: People First: Full Engagement
Authors: Al-Khalifa Abdul-Jaleel 
Published: February 2015

When oil prices dipped in the mid-1980s, many companies went through downsizing or "rightsizing" initiatives. A major surge of mergers and industry restructuring followed through the 1990s. Companies had to scale down their workforce to lower their annual direct expenditure, and the notion of doing more with less became very familiar. Unfortunately, the layoffs caused many talented experts to migrate to what they perceived to be more stable industries. Student enrolment in petroleum engineering schools had also suffered a drastic decline, drying the pool of new graduates joining the industry for many years. The recent growth and expansion of industry activities is faltering because of a scarce talent pool, a skewed demographic of an ageing workforce, and a thin pool of new graduates. Striving to recruit additional human resources, some companies were more creative in revising their human resources policies, including salary structures and benefit plans. Industry-wide, the process was a zero-sum game where companies continued to poach professionals from other companies within the same industry. The painful and inefficient "hiring and firing" cycles have to be eradicated in favor of a 10- to 15-year staffing plan that results in more efficiency and enduring stability.
The current unprecedented industry growth and strained human resources calls for full engagement and utilization of the current industry workforce. Indeed, it is quite alarming to hear many industry experts complaining that their potential is not fully utilized. It is also often reported that new graduates joining our industry are initially very inspired and motivated, but tend to lose their energy and passion after being in the industry for only few years. What can the industry do to ensure the full utilization of our employees' potential? To better assess the situation, in December 2005 SPE conducted a survey to assess attributes related to employee engagement and job satisfaction.
Overview: Horizontal and Complex Trajectory Wells (November 2006)
Authors: Stone Charles R. 
Published: February 2015

Horizontal drilling required approximately 15 years to evolve into a mature technology. During this time, the petroleum industry witnessed amazing feats of extended-reach technology, updip horizontal drilling, rotary-steerable technology, and now directional drilling with casing.
Horizontal drilling became feasible in the 1980s with the emergence of measurement-while-drilling downhole survey tools. Horizontal drilling continues to be a powerful application for exposing more reservoir per motherbore (multilaterals), increasing productivity from tight rock, acquiring exposure to multiple subsurface compartments, producing heavy-oil reservoirs (with steam-assisted gravity drainage), and managing waterdrive reservoirs.
It is a particularly strong application in clean sandstones with low-vertical-permeability barriers. However, horizontal drilling also can address thin-layered petroleum traps with poor-to-low horizontal permeability. Horizontal completions are limited only by the imaginations of those who drill horizontally.
There soon will be a day when one builds a curve considerably below the level of the lateral and places a subsurface pump below the level of production. How many of Earth's petroleum reservoirs are shallow, have no reservoir pressure, cannot be drilled vertically economically, and yet will respond to gravity drainage in a horizontal wellbore?
Horizontal and Complex-Trajectory Wells additional reading available at the SPE eLibrary: www.spe.org
IPTC 10966 "Reservoir-Screening Methodology for Horizontal Underbalanced-Drilling Candidacy" by T. van der Werken, SPE, Weatherford, et al.
SPE 102678 "Analyzing Under performance of Tortuous Horizontal Wells: Validation With Field Data" by M. Kerem, SPE, Shell Intl. E&P B.V., et al.
SPE 101129 "Development of Small- and Medium-Sized Oil Fields Through Horizontal Wells—The Way Ahead" by R.D. Tewari, SPE, Greater Nile Petroleum Operating Co., et al.
SPE 92804 "Coiled-Tubing Reverse Circulation—An Efficient Method of Cleaning Horizontal Wells in a Mature Pressure-Depleted Field" by P. Santhana Kumar, SPE, Petroleum Development Oman, et al.
Overview: Gas Production Technology (November 2006)
Authors: Wichert Edward 
Published: February 2015

The gas-production and -processing industry continues to apply new technologies, as well as improve old technologies, to produce gas and bring it to market. For many years, gas in remote locations had virtually no value because markets were not within economic reach by pipeline. In recent years, with the increase in the value of oil and the products derived from oil, technologies to convert natural gas chemically to liquid hydrocarbons are being applied to monetize remote gas. This increase in gas-liquefaction capacity is in addition to the older technology that physically changes phases of natural gas from gaseous to liquid by deep cooling for transportation to market.
Natural gas often is produced from tight geological formations. To produce gas from low-permeability reservoirs economically, it is necessary to hydraulically fracture the rock. This process requires pumping a large amount of water or a suitable hydrocarbon liquid at high pressure as carrier fluid for the proppant. Minimizing the leakoff of the fluid being pumped enhances the effectiveness of such stimulation treatments. New approaches to the selection of specific fluid additives, designed to reduce surface tension and leakoff, can extend the fracture length and increase the well's productivity.
A common hindrance to gas production in low-productivity gas wells is the ever-present problem of coproduction of water. While this problem has been studied extensively in the past, new technology can be combined with existing technology to extend the productive life of low-rate gas wells. For high-pressure gas production, a reduction of the water vapor contained in the produced gas can be achieved through the application of supersonic nozzles, in place of traditional dehydration methods.
The above-mentioned topics and other innovations regarding gas production technology were examined in papers presented during the past year at various SPE technical meetings worldwide.
Gas Production Technology additional reading available at the SPE eLibrary: www.spe.org
SPE 100442 "Selective Removal of Water From Supercritical Natural Gas" by A. Karimi, Memorial U. of Newfoundland, et al.
SPE 98285 "Arqumia Field: Mexico's Highest-Deliverability Gas Well" by A.E. Guzmán, SPE, Pemex E&P, et al.
SPE 97070 "Identifying the Timing and Sources of Damage in Gas-Storage Wells Using Smart Storage Technology" by J.P. Spivey, SPE, Phoenix Reservoir Engineering, et al.