bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mud Design To Prevent Circulation Losses
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105449, "Design of Well Barriers To Combat Circulation Losses," by Bernt S. Aadnoy, SPE, Mesfin Belayneh, SPE, and Miguel Arriado, U. of Stavanger, and Roar Flateboe, BP plc, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February.
The full-length paper summarizes a 10-year research program in borehole fracturing and mud design. Numerous experiments were conducted with oil- and water-based drilling fluids to understand better the mechanisms that lead to circulation losses. A new mechanistic model for fracturing is presented that is different from other recent models, and the model was verified with laboratory experiments. The model defines optimal barrier filtrate loss to place particles in the loss zone. Selected laboratory experiments are presented that demonstrate that borehole fracturing resistance can be improved significantly by changing mud composition.

Introduction
Recognizing that borehole-stability mechanisms are not understood fully, research carried out during the past 10 years has focused on the fundamental physics and chemistry. Fig. 1 shows a fracturing cell where specially prepared hollow concrete cores are fractured. The setup also allows for mud circulation to ensure that mud particles are well distributed inside the hole. The cell is rated to 69 MPa, and the axial load, confining pressure, and borehole pressure can be varied independently. Many oil- and water-based drilling fluids were tested as well as novel ideas such as changing rock wettability or creating other chemical barriers. Cores with circular, oval, and triangular holes were tested to study effects of hole geometry.
Fig. 2 shows typical results from the fracturing experiments. The commonly used Kirsch equation defines the theoretical fracture pressure in a nonpenetrating situation such as when using drilling muds. Only one of the three measured fracture pressures agrees with the theoretical model, and the other two are much larger. Several conclusions came out of this research.The theoretical Kirsch model underestimates the fracture pressure in general.There is significant variation in fracture pressure, depending on mud quality.
This shows that the fracture pressure can be increased by designing a better mud.
Several devices were constructed to study the mud and its filter cake. Fig. 3 shows a mud cell with six outlets to simulate fractures of various dimensions. The mud is circulated with a low-pressure pump to develop a filter cake across the slots. Then, a high-pressure pump increases the pressure until the mudcake breaks down. In this way, the stability and strength of the mudcake can be studied. Common muds and additives were used, and the observation was made that reducing the number of additives often results in a better mud. Nonpetroleum products also were studied to look for improvements.
Overview: Tight Reservoirs (November 2007)
Authors: Mayerhofer Mike 
Published: February 2015

Nothing has changed over the last year; high oil and gas prices are still providing a major boost to tight-reservoir development. However, costs have been rising because demand for services is high. North America has seen a "boom" of startup service companies that specialize in pumping hydraulic-fracture treatments. A surge of horizontal-well development in shale reservoirs is one of the reasons for the significantly increased demand for hydraulic-fracturing services. Instead of one fracture treatment per vertical well, horizontal wells are treated with up to a dozen individual fracture treatments in a short period of time requiring enormous amounts of water and fracturing materials on location. Moreover, in some cases, two to three offsetting horizontal wells are fracture treated simultaneously to achieve the best possible stimulation and drainage efficiency.
In addition to "supertight" shale reservoirs, horizontal-well development also has moved back into the more traditional domain of tight-sandstone reservoirs, such as the Cotton Valley in east Texas and others. Significant advances in drilling efficiency and technology have been made as a result of this high activity, enabling high flexibility for well trajectories while providing a wellbore that meets the needs for the specific completion strategy. Horizontal-well completion strategies include mainly cased-and-cemented wells, but recently, uncemented laterals with openhole packers for stage isolation have become more popular because an entire wellbore can be fracture stimulated with back-to-back treatments in a single day. Diagnostic technologies, such as microseismic and tiltmeter fracture mapping and radioactive and chemical tracer logs, complement innovative drilling and completion technologies by providing a picture of what is happening during fracture treatments and showing how efficient the different completion technologies are in stimulating the entire horizontal wellbore.
In conclusion, times are still exciting for tight reservoirs and likely will continue to be that way for many years to come.
Tight Reservoirs additional reading available at the SPE eLibrary: www.spe.org
SPE 102745 "4D Pressure Pilot To Steer Well Spacing in Tight Gas" by E. Quint, Shell E&P Americas, et al. [See JPT (February 2007) 86]
SPE 108110 "Productivity and Drainage Area of Fractured Horizontal Wells in Tight Gas Reservoirs" by F. Medeiros, SPE, Petrobras, et al.
SPE 102801 "Imaging Seismic Deformation Induced by Hydraulic-Fracture Complexity" by S.C. Maxwell, Pinnacle Technologies, et al. [See JPT (March 2007) 54]
Your SPE: Enhancing the SPE Value Proposition in China
Authors: Roodhart Leo 
Published: February 2015

President's column
One of my last trips as President-Elect was to China. My visit was marked by two key events: the recent tragic earthquake in Sichuan and the excitement leading up to the Olympics. These topics were on every agenda, together with SPE and the oil industry, of course.
I went to China to talk to company leaders and representatives of four of the five active sections about how the industry might develop over the next 20 years and how SPE can help it to respond to a rapidly changing world. There must be millions of engineers in this country with a population of over 1.3 billion people. But total SPE membership is just 1,740, with most members belonging to the Beijing, Daqing, Northern China International, and Southern China sections. My challenge in China was to communicate SPE's value proposition: SPE is not just about conferences and workshops but has a role as a relationship broker between engineers and the providers of knowledge. It provides a vehicle for individuals and companies to maximize business and networking opportunities through events, publications, and electronic media—a concept that the senior management of the Chinese NOCs finds difficult to understand. They view SPE membership as valuable at a corporate level, offering "a window on the external world." The senior company executives have calculated exactly how many members they need to ensure an effective distribution across their organizations of JPT magazines, access to the eLibrary, and notice of upcoming workshops and conferences. They are very supportive of SPE's sister organization in China, the Chinese Petroleum Society, which publishes many Chinese technical papers and hosts events around the country.
Dues of members in the Beijng, Daqing and Southern China sections are paid by their companies. Membership numbers will increase only as a result of further added value rather than from lower dues. So, how do we boost membership in China?
Discussions during my meetings offered a few solutions. All sections requested that we set up a program of regional (meaning Chinese) Distinguished Lecturers and a Chinese-language professional network targeting those nationals who work outside China. However, Chinese translations of SPE papers was not seen as adding value, particularly in the China National Offshore Oil Corporation, where the objective is to encourage engineers to learn English.
I am one of SPE's main advocates of further globalization of the Society, so how do I match that objective with listening to local needs that call for a more insular approach, which is totally in keeping with the Chinese culture and which we must respect?
Acid-Tunneling Technique Shows Success in Carbonates
Authors: JPT staff _ 
Published: February 2015

Technology Update
Rising oil prices and increased efforts to maximize oil production have created global interest in technologies that economically can extend well lifetime. As fields mature, stimulation technology costs become marginally economic as production improvements decline.
For wells completed openhole in carbonate reservoirs around the world, an acid-tunneling technology developed by BJ Services has been shown to provide an economic and efficient stimulation alternative.
The patented process, called StimTunnel, uses coiled tubing (CT) to convey a jointed nozzle that jets acid at the formation rock, dissolving it to create numerous mechanically stable, stimulated tunnels into the formation (Fig. 1). These tunnels, and the multitude of wormholes and expanded pores, increase reservoir contact and improve productivity by distributing inflow across more surface area (Rae and di Lullo, 2001).
Applicable in openhole completions in limestone or dolomite formations, the technology does not require a drilling rig and has no fluid returns, resulting in very low environmental impact.
Economically, the acid-tunneling compares favorably with alternative stimulation options in both cost and time savings. This is especially true when considering resulting production improvements.
The use of these treatments began in Venezuela, Spain, and Indonesia, and recently has spread to Kuwait, Romania, the US, and Libya.

Early Results
The initial field trials of the technology were in the massive Mara carbonate field near Lake Maracaibo, Venezuela, during 2005, where typical permeability is in the range of 1 to 5 millidarcies (md).
In operation, the jointed tool is run on CT to the desired tunneling kickoff depth. Acid is pumped, and the internal CT pressure activates the kickoff tool to make contact with the formation face. Acid is jetted from the nozzle, dissolving the formation face and forming a tunnel entry area in the rock matrix. After tunnel initiation, the CT run into the well will push the tool into the reservoir so that the acid can dissolve more of the formation ahead. When the desired tunnel length is attained, pumping ceases and the CT is pulled out of the tunnel. This process is repeated higher uphole as many times as required, at different elevations.
Typical tunnel lengths vary from 3 to 60 ft, although tunnels longer than 100 ft have been created. Because it is intended for relatively short tunnels, the bottomhole assembly (BHA) does not incorporate a steering tool or telemetry systems to relay inclination or azimuth information back to surface.
Progress and Challenges for Health, Environment, and Safety in Exploration and Production
Authors: Arscott Lyn 
Published: February 2015

Management
A computer-based survey was taken of the program committee members of five SPE International Health, Safety, and Environment (HSE) Conferences over the past 5 years. The committee members are experts in their fields and they were asked to express their opinions on the progress of the industry in HSE over the past 5 years and the effort that the industry should make over the next 5 years.
The committee members were asked to complete a web-based questionnaire with the following questions:How would you rate the progress made by the industry in the following subjects over the past 5 years? (excellent, good, moderate, poor, very poor)How would you rate the effort that the industry should make in the next 5 years? (much more effort, more effort, same effort, less effort, much less effort)How would you rate the effort the regulators should make in the next 5 years? (much more effort, more effort, same effort, less effort, much less effort)How would you rate the effort that the nongovernmental organizations (NGOs) should make in the next 5 years? (much more effort, more effort, same effort, less effort, much less effort)
The method of scoring and ranking is summarized in the appendix. A summary of the status of the industry programs is shown in Table 1 with the full results in Tables 2–4. Of the list of 20 questions, 16 were asked at all five conferences but 4 new questions were asked at the 2008 conference in Nice, France.
The chart in Fig. 1 shows the scores for progress from the Nice (2008) conference. The seven issues in the first column of Table 1 are the highest-ranked items in the Progress list based on the results from Nice as shown in Table 2 and have been categorized as "good progress," while the six issues in the third column of Table 1 are the lowest-ranked issues from the Progress list and have been categorized as "needs more effort." The issues in the second column are those issues in between the other two categories and have been categorized as "maturing." The issues in the table are, therefore, in seriatim order for the progress scores and the numbers in the parentheses are the rank for the future effort score.
Minimizing Risk of Gas Escape in Gas Storage
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113509, "Minimizing Risk of Gas Escape in Gas Storage by In-Situ Measurement of Gas Threshold Pressure and Optimized- Completion Solutions," by L. Ostrowski, SPE, Baker Hughes, and B. Ulker, RWE Dea A.G., originally prepared for the 2008 SPE Europec/EAGE Conference and Exhibition, Rome, 9-12 June. The paper has not been peer reviewed.
Underground gas-storage operations and carbon dioxide (CO2) sequestration in aquifers rely on proper wellbore construction and on the sealing function of the caprock. Potential leakage paths are by migration along the wellbore as a result of poor cementation and flow through the caprock. Capillary pressure data, which are critical for prediction of gas leakage through the caprock, are seldom available and yet are necessary. An in-situ method of determining gas-entry pressure was developed to help reduce uncertainties in gas-leakage predictions. Simulations were performed using this gas threshold entry pressure to investigate the gas leak-age amount through the caprock and along the wellbore for both natural-gas- and CO2-storage models.

Introduction
Capture and geologic storage of CO2 are being considered to reduce CO2 emissions. Managing geological storage requires an understanding of the processes and risks, including the likely time scales and flux rates involved. Key processes are the migration of CO2 after injection into deep geologic formations, stratigraphic trapping, dissolution, residual-gas trapping, mineralization, and potential leakage. The storage capacity of an underground CO2-storage project must be related not only to the amount of CO2 that can be stored but also to long-term storage effectiveness. Experience with underground natural-gas storage provides useful insight into the geologic storage of CO2. Both methane (CH4) and CO2 are less dense than the usual formation water and thus exhibit a tendency to migrate to the top of the storage formation. Potential leakage of CO2 and CH4 from the storage formation can occur through the caprock, along the wells, and through faults and fractures. In many instances, underground natural-gas- storage projects are operated at pressures exceeding the initial reservoir pressure. Overpressurization usually occurs at the early stages of storage and is essential for increasing storage capacity and gas deliverability. This overpressure can result in pushing water out of the caprock and causing gas to leak from the storage formation. In CO2-storage projects, less is known about the risks of leakage through the caprock because of lack of experience. It is essential to determine the gas-entry pressure into the caprock before proceeding with any gas-storage project.
Comments: Weathering the Recession
Authors: Donnelly John 
Published: February 2015

Editor's column
A new report sheds light on how oil and gas firms have weathered the recession, and whether the firms" management believes that the industry is experiencing permanent structural changes in addition to the significant economic downturn.
Released on the eve of the SPE Offshore Europe conference, the report concludes that companies generally fall into one of two categories and that the determining factor is company leadership and corporate culture. Although the entire industry has been affected by the recession and the cyclical nature of oil prices, the study sought to discover why some firms are more resilient and optimistic when facing economic and other challenges. The "Riding the Rapids" survey was put together by the Aberdeen School of Business and the Production Services Network consulting firm and was based on interviews with senior leadership from oil and gas operators and service companies. The research was then debated and discussed in panel sessions held in Aberdeen, Houston, Calgary, and Abu Dhabi.
Companies were split on how they viewed current economic challenges. More than three-quarters of the companies said they had been affected in some way by the banking meltdown and the oil-price volatility of the past year and a half. But just over half (51%) claimed they were immune or only moderately affected by the current economic downturn and seemed to welcome the challenges the downturn posed. In sharp contrast, 49% of the companies surveyed "felt exposed and less in control of their destiny, stating they had been seriously or very badly affected by the current recession."
The more optimistic firms saw the recession as only one of several contextual factors driving change in the industry. They also saw more signs of economic and industry recovery occurring in the second half of this year, which could lead to an industry rebound in 2010. Management in these companies were focused on restructuring their companies to become "leaner and meaner" in days to come to perform more efficiently. Not surprisingly, these firms often had a product line that was more economically inelastic, diversified offerings, and sound management practices and sturdy financials that were already in place. Some saw a practical opportunity to the boom and bust economic and price cycles the industry weathers—it allows the industry to periodically realign itself to current economic realities, streamline costs, and emerge as a more efficient sector.
The more vulnerable cited the banking crisis in particular as a factor, as the lack of access to capital and funding harmed the ability to secure finance for projects and new developments and affected cash flow throughout the supply chain. They also cited a lack of skilled workers. The industry faced that problem before the recession and economic difficulties only made matters worse for some firms, which laid off workers even in light of the technical-talent shortage. Other firms in this category also complained about the lack of help and incentives from government, even as it bailed out other industries.
Bringing the Digital Oil Field to Production Operations
Authors: Mahdavi Mehrzad , Darukhanavala P.P. (Duru) , Paul Donald 
Published: February 2015

Guest editorial
Things move fast in the world of digital technology. And the oil industry has often been in the advance guard.
Progress in the seismic area, accelerated by high-performance computing, has been nothing short of amazing, and the industry has truly pushed the envelope in deepwater exploration thanks to adoption of vanguard technologies. In addition, the industry has advanced significant initiatives to digitize field operations, from installing field wireless networks and sensors to deploying wellbore fiber optics.
However, upon reflection, most progress has come in exploration or field development. In "operations," the Digital Oil Field of the Future (DOFF) has moved ahead in small, measured steps. Is it possible to accelerate adoption of digital innovation in the traditional, cautious world of production operations?
The external world has experienced an explosion in the development and adoption of new digital technology. In the past decade, the Internet has morphed from minor brochureware to a major business channel and the smartphone has become a game-changing device right out of the gate.
The next generation of computing—cloud computing—is taking shape in a big way, bringing game-changing technologies and business models.
And so—could our progress in the oil field be faster? The complexities and barriers are significant. Four in particular impact the pace of change:Wide Diversity of Industry, Assets, and Participants. Production-operations deals in new fields and brownfields, international oil companies (IOCs), national oil companies, and independents, all have different value propositions. There can be no "one size fits all" DOFF solution. This diversity and a lack of focus in industry efforts supporting DOFF have led to small-scale, independent DOFF efforts across—and even within—companies. The consequent slow progress and disconnected processes have made it difficult to mount efforts that reach economies of scale.Lack of Industry Standards. Suppliers have a vested interest in protecting their proprietary solutions rather than developing industry standards; likewise, IOCs are inclined to see their DOFF initiatives as potentially providing competitive advantage, reducing any willingness to share. However standards and integration of technologies will be essential to reach the economies of scale necessary to drive widespread adoption.
Comparing Friction Reducers' Performance in Produced Water from Tight Gas Shales
Authors: Ferguson Marcelle L. , Johnson Michael A. 
Published: February 2015

Technology Update
Natural gas plays a key role in meeting the energy demands of the United States, and the production of natural gas from tight shale formations is expanding rapidly as the demand for clean and efficient energy rises. Slickwater fracturing, a hydraulic fracturing technique whereby a water-based fluid is injected into a well at intense pressures—causing the formation rock to crack, or fracture—is the most commonly used stimulation technique in tight gas reservoirs. Slickwater fracturing treatments involve combining a base fluid with a friction reducer, a polymer that enables faster pumping of the fluid into the formation, and a propping agent, or proppant—a granular substance, such as sand, that is carried into the formation by the fluid and holds the fractures open once the treatment is complete.
Each stage of a slickwater-fracturing treatment requires tens of thousands of barrels of fracturing fluid. Furthermore, each slickwater treatment generates a great deal of wastewater, as most of the fracturing fluid will flow back out of the well, and production brines, or produced water, will flow back over the long term. Programs for managing produced water are on the rise, as technology for convenient and economical treatment of wastewater improves. However, often the most cost-effective and convenient use of produced water is to reuse it in subsequent fracturing treatments.
Evaluation of friction-reducer performance in the reused water is crucial because produced water from most of the US tight shale formations contains elevated levels of dissolved solids, compared with fresh or tap water. Reusing waters with high levels of total dissolved solids (TDS) can lead to adverse interactions between the friction reducer and the base fluid. The adverse interactions result in elevated treating pressures, and this is often overcome by introducing more of the friction reducer into the mixture, which leads to higher chemical costs for the treatment.