bluuebunny/crossref_metadata_2025_split huggingface dataset:
Testing for Life
Authors: Soliman Hatem 
Published: February 2015

Management
Well testing provides answers you cannot get any other way. Whether testing is performed during exploration and appraisal, development, or production, it provides the greatest levels of security to support decisions—decisions that can affect the reservoir for its active life.
At today's commodity prices, it has become increasingly important to differentiate reservoir description from reservoir characterization. Reservoirs can be described in many excellent and reliable ways: with seismic images, with geologic or petrophysical analyses using well data taken during drilling or logging, or by monitoring production parameters from nearby wells. These methods all tell what the reservoir looks like, but they do not tell how the reservoir will behave over time.
Now, much more than simple reservoir description is possible. Today we can see the big picture, looking deep within the reservoir to get insights about the reservoir fluids and their dynamics. Reservoir characterization is about proving a reservoir's potential, confirming its performance, and improving its productivity. Testing accomplishes this by providing a better basis for all sorts of life-of-reservoir decisions, including how much to invest, where to place additional wells and how to complete them, how to enhance and sustain production, and how to minimize risk.
Reservoir characterization is achieved by combining the best reservoir description parameters with reservoir behavior analysis derived from testing. Today's critical reservoir decisions demand the very best information available—saying "no" to testing is not an option. Testing transcends static well descriptive data by providing insights on what is going on between wells with analysis of pressure and flow under controlled conditions. Testing reacts to formation and fluid heterogeneities that are invisible to seismic and discontinuous between wells or levels. With modern testing analysis, heterogeneities can be characterized and their long-term effects predicted.

Testing is Back, With Added Value
The old days of the oilfield, with derricks and pumpjacks sprouting up everywhere, are over. Today, operators strive to drill fewer, but much better, wells. They take great pains to steer wellbores into the highest quality reservoir sections, to understand and exploit each reservoir compartment, and to maximize return on capital. To accomplish this requires accurate and timely information, and testing can provide the critical data to fill the gaps in the dynamic reservoir model. With accurate reservoir characterization, wells can be properly placed, completion intervals and techniques can be optimized, and productivity forecasts and decline curves can be more precise. Surface facilities can be properly scaled and reservoir drainage patterns can be better understood, leading to more effective injection programs.
The Cement Packer: A Simple and Economic Method of Accessing Bypassed Reservoir Potential
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108973, "Multitype Application of Cement Packer: Simple and Economic Method of Accessing Bypassed Reservoir Potential," by Muhammad Idris, SPE, Martin Rylance, SPE, and Krisjahbana Joenoes, Vico Indonesia, and Nanang Firmansyah and Anton Supriyono, Halliburton Indonesia, originally prepared for the 2007 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 30 October- 1 November. The paper has not been peer reviewed.
Cement-packer operations offer a potentially attractive economic opportunity for a rigless intervention to add additional hydrocarbon potential to a well. The full-length paper details the steps involved in this operation. The cement-packer process was first introduced in 1995; since then, a number of variants of the approach have been developed and applied. These variants have been driven in response to individual-well limitations, special requirements, and increased technical understanding and experience.

Introduction
The Sanga Sanga Production Sharing Contract (PSC) fields are in the onshore part of the Mahakam delta, East Kalimantan, Indonesia. Vico Indonesia has been actively exploring and developing fields within the Sanga Sanga PSC since 1968. The initial exploration drilling phases resulted in the discovery of the giant Badak and Nilam fields. Over the next decade, additional commercial discoveries were made to the west, along the Sanga Sanga anticline—namely, the Semberah and Mutiara fields.
The hydrocarbon accumulations are located in the Middle Miocene sequence of numerous distributary-channel sandstone reservoirs, with mixed structural and stratigraphic trapping mechanisms. A combination of a highly complex fluvial-deltaic environment and increasing field maturity has resulted in a significant challenge for ensuring a continuous development strategy for the remaining reserves while maintaining economic conditions to meet commercial requirements.

Completion Philosophy
The completion philosophy, within the Vico developments, has evolved over the years. In the early field developments, between 1970 and 1994, the philosophy was to use multiple strings. Typically, a well was drilled with a 12 1/4-in. hole through the F Sands and a 9 5/8-in.-casing string was run. Subsequently, an 8 1/2-in. hole was drilled across the deeper G Sands, and a 7-in. liner was run to total depth. The wells then were completed with two separate produc-tion strings and selective completions (Fig. 1). The tubing strings were either both 3 1/2-in. or a combination of 3 1/2- and 2 3/8-in. strings. Only a single string would penetrate the 7-in. liner (referred to as the long string), with selective zones isolated between packers and behind sliding sleeves within the 7- and 9 5/8-in. sections, where the second string terminated (referred to as the short string).
Technology Focus: Reservoir Performance and Monitoring (September 2008)
Authors: Clemens Torsten 
Published: February 2015

Technology Focus
The draft European Directive for carbon capture and sequestration requires monitoring of potential leakage from CO2-storage sites. In this case, monitoring is a method of improving efficiency and will be mandatory for obtaining permission for such projects. Whereas monitoring the movement of the CO2 plume offshore can be achieved at reasonable costs, onshore monitoring leads to high costs and difficulties because of disturbance of residents if seismic is used. Several potential CO2-storage sites are onshore; therefore, monitoring methods that are low-cost and have a limited effect on the public are required. Conventional hydrocarbon production will benefit from this mandatory push for new technology.
One such method might be the use of microgravity, which recently was used successfully to monitor the movement of gas in an underground gas-storage project. By advancing this technology, its application envelope might expand even further into miscible- or immiscible-gas-injection enhanced-oil-recovery projects.
Another method used increasingly for monitoring is microseismic. Induced microearthquakes are considered the result of slippage or tensile deformation and can be detected at nearby seismic receivers. Even though the effects are not understood well, in tight gas formations, microseismics is used to monitor the direction and growth of induced fractures. The first featured paper shows the expansion of this technology into other hydrocarbon-production activities.
Less than a decade ago, the hydrocarbon-production industry discussed ways to cope with a world of low oil prices. This situation has changed dramatically. To optimize income from current high hydrocarbon prices, well-productivity loss from impairment must be minimized. The second featured paper describes a method of detecting such underperforming wells in real time.
Assuming that high hydrocarbon prices prevail, unconventional hydrocarbon resources, of which large quantities exist, come into focus. Today, hydrocarbons such as bitumen or shale gas, which for a long period of time were produced in relatively small quantities compared with conventional hydrocarbons, are high on the agenda of oil- and gas-producing companies. To date, methane hydrates are considered to be one of the most unconventional resources with large hydrocarbon volumes in place. The third paper discusses how these reservoirs could be produced.
Reservoir Performance and Monitoring additional reading available at the SPE eLibrary: www.spe.org
IPTC 11370 • "Seawater in Chalk: An EOR and Compaction Fluid" by Tor Austad, University of Stavanger, et al.
IPTC 11375 • "Reservoir Connectivity: Definitions, Examples, and Strategies" by John W. Snedden, ExxonMobil, et al.
Additional reading available at OnePetro: www.onepetro.org
OTC 19445 • "Fiber-Optic 4C Seabed Cable for Permanent Reservoir Monitoring" by Steve Maas, Petroleum Geo-Services, et al.
Reducing the "Data Commute" Heightens E&P Productivity
Authors: Brule Michael , Charalambous Yanni , Crawford Mark L. , Crawley Charles 
Published: February 2015

Management
In information management and decision making, the "data commute" emerges repeatedly as a big problem in achieving more efficient workflows. SPE's Digital Energy Technical Section has conducted several in-depth statistical studies that show an unacceptable amount of time in the E&P workforce lost searching for data, integrating it from multiple sources, and preparing it for analysis in applications (Brulé et al. 2008; Hite et al. 2007; Mochizuki et al. 2006). Once engineering and operational data are in the application package for analysis, any updated or more recent data require a repeat of tedious, barren, and nonproductive processes to prepare and reload the data, a sort of "oilfield entropy" that is a drag on the E&P industry. The time that could have otherwise been spent making operational or project decisions is lost to activity that has nothing to do with engineering and geoscience.
Some industry professionals might be resigned to dealing with data as just part of the workday, but most recognize a fundamental tenet: it is not the data per se, but decisions—based on data-derived information—that drive actions and create value(Fig. 1). We acknowledge the importance of engineering techniques, operational effectiveness, risk-factor evaluation, and project methodology, but here we separate them to examine and quantify just one assertion: making informed decisions would be quicker if the underlying necessary data are always ready to go. "If I can make that decision accurately, but a month earlier, and can do this across many projects, many wells, many fields…." Faster decisions with precision have tremendous value and provide much leverage in an industry already hindered by a shortage of qualified people.

Contexts of Oilfield Integration
Oilfield integration spans all areas of the oil and gas industry, from subsurface to surface to business. International oil companies (IOCs) currently have several oilfield-integration efforts as initiatives. Understanding the context of these oilfield integrations is important to understand what the IOCs are trying to accomplish. When we speak of integration, just what are we actually integrating? There exist several contexts of integration that must be recognized and accomplished to realize the vision of the digital oil field:Data integration—Data accessible to everyone, across disciplines, and consumable in softwareWorkflow and process integration—Combining and automating work processes for greater efficiencyDisciplines integration—The leverage of experts across disciplines like the geosciences, drilling, production, and reservoir (Mochizuki et al. 2006; Sankaran et al. 2009)
Designing Swellable-Elastomer Packers in Fracturing Operations
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20157, "Design Methodology for Swellable-Elastomer Packers in Fracturing Operations," by Rutger Evers, SPE, Dustin Young, SPE, Greg Vargus, SPE, and Kristian Solhaug, SPE, Halliburton, prepared for the 2009 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed.
The value of swellable-elastomer technology is its ability to form a permanent seal by elastomeric expansion in hydrocarbon or water. One application is swellable-elastomer packers (SEPs) in acid-stimulation and hydraulic-fracturing operations. The design process included modeling of down-hole parameters and anchoring forces. Laboratory testing included thermal-contraction measurements developed to resolve technical challenges for stimulation operations.

Introduction
The initial application of swellable elastomer was swellable elements for packers designed to provide zonal isolation in an openhole environment. Now, swellable elastomers are used in many applications. A recent application is in stimulation operations, in which SEPs were subjected to a very specific set of conditions that significantly affect the sealing performance of the tool(s).
Three primary challenges must be addressed when designing SEPs for stimulation applications.Downhole conditions—the main parameters to which the tool will be subjected, such as the downhole pressure and the average temperature of the sealing elements.Anchoring forces—forces from the shrinkage of the pipe during the treatment that, in turn, subjects the SEPs to additional forces that do not occur in conventional zonal-isolation applications.Thermal contraction of the sealing element—contraction resulting from injection of stimulation fluids that will reduce the temperature of the packer. This phenomenon causes partial loss of contact of the sealing element and results in altered sealing properties. Ultimately, pressure-seal loss can occur.
Hydraulic Fracturing and SEPs One area of research and development is in hydraulic fracturing, and by combining multidisciplinary fields of expertise, reliable designs have been developed. Pump rates and volumes of fluids pumped usually are high and can be from 40 to 90 bbl/min. With such high rates, the fluids will remain cool while being pumped downhole, resulting in a cooling effect of the fluid on the tubing side of the packer.

Design
Two parameters, temperature and pres-sure, have a major role in designing an SEP, especially for stimulation operations. Pressure has always been a main parameter for SEP design, but for stimulations, the temperature effect on the differential pressure (DP) across the SEP must be taken into account.
Technology Focus: Reservoir Performance and Modeling (September 2009)
Authors: Vikane Erik 
Published: February 2015

Technology Focus
"Reservoir engineering is a complex subject for two reasons. In the first place, we never see enough of the reservoirs we are trying to describe. Therefore, it is difficult to define the physics of the system and, therefore, select the correct mathematics to describe the physics with any degree of certainty. The second problem is that even having selected a sensible mathematical model, there are never enough equations to solve for the number of unknowns involved" (Dake 2001).
Prudent reservoir management requires active reservoir surveillance to optimize reservoir performance. The challenge for reservoir engineers is to justify the additional cost involved in gathering data and also to transform those data into valuable information. The paper describing an integrated reservoir-surveillance process for the greater Burgan field in Kuwait is an excellent example of how to justify implementing a systematic surveillance process.
Lack of data and lack of confidence in data are major challenges in developing brownfields. The paper "Revitalization of Old-Asset Oil Fields Into I-fields" describes how old fields can benefit from the application of modern surveillance technology.
The trend toward intelligent fields has increased the use (and demand) for real-time reservoir management. To take advantage of the continuously and rapidly increasing amount of data, the industry will need a workflow shift from the deterministic approach to one based on statistical approaches. The paper "Where is the Gap? Is It in More Reservoir Engineers or in Leveraging New Skills and Workflows That Enhance Individual Productivity?" examines how reservoir engineers can improve productivity by use of statistical concepts and workflows.
The additional reading addresses some of the challenges the industry is facing in developing unconventional hydrocarbon resources—in this case, shale gas.

Reference
Dake, L.P. 2001. The Practice of Reservoir Engineering, ix. Amsterdam: Elsevier.
Reservoir Performance and Monitoring additional reading available at OnePetro: www.onepetro.org
SPE 119892 • "Impact of Shale Properties on Pore Structure and Storage Characteristics" by R.M. Bustin, University of British Columbia, et al.
SPE 119897 • "Production Analysis and Forecasting of Shale-Gas Reservoirs: Case-History-Based Approach" by L. Mattar, SPE, Fekete Associates, et al.
Technology Focus: Wellbore Integrity, Sand Management, and Frac Pack (September 2009)
Authors: Goodman Harvey E. 
Published: February 2015

Technology Focus
Technology development in our industry continues to boost efficiency and profitability in existing fields, while enabling exploration and development in more-remote and -hostile geological environments around the world. Wellbore integrity, sand management, and frac-pack-completion technologies each can have a tremendous effect on oil-/gas-asset performance. When each technical theme is linked to provide a comprehensive model, risk and uncertainty of asset design and operation can be diminished greatly.
As an example of linking formation integrity to sand management, one of the papers highlighted this month describes how sand-control campaigns can morph, or change, over time as field performance is monitored, areas of improvement are identified, and solutions are implemented by use of new completion technologies. This sand-control-philosophy change stems from an understanding of the reservoir-failure mechanism, a thorough knowledge of sand-exclusion-device options, and careful consideration of completion-fluid-sensitivity performance.
Furthermore, recent implementation of a new sand-control technology for extensive, stacked reservoir intervals provided an option that can significantly reduce rig time associated with the completion. A highlighted paper discusses this completion technique, describing execution for conventional gravel-pack and frac-pack sand-control completions.
With regard to borehole-fluid exposure to the formation over time, another highlighted paper introduces a shale-core stability-test procedure that enables field-applicable comparisons of whole water-based muds. The differences in shale-stability preservation are striking. The results are presented in a fashion that blends good science and careful laboratory procedures with practical linkages to the field.
Wellbore Integrity, Sand Management, and Frac Pack additional reading available at OnePetro: www.onepetro.org
SPE 114273 • "Casing Ultradeep, Ultralong Salt Sections in Deep Water: A Case Study for Failure Diagnosis and Risk Mitigation in Record-Depth Well" by Jincai Zhang, SPE, Shell, et al. (See JPT, May 2009, Page 78.)
SPE 120219 • "Prediction of Wellbore Stability Using 3D Finite-Element Model in a Shallow Unconsolidated Heavy-Oil Sand in a Kuwait Field" by K. Ahmed, SPE, Kuwait Oil Company, et al.
Temana Field: A Shift in Sand-Control Philosophy
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12390, "Temana Field Pilot Implementation: A Shift in Sand Control Philosophy To Improve Well Performance," by Wan Amni Bt Wan Mohamad, SPE, Maharon Jadid, SPE, and Mahmoud A. Wahba, SPE, Petronas Carigali Sdn. Bhd., originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.
The Temana field consists of unconsolidated reservoirs that require active sand control. The conventional internal-gravel-packed (IGP) technique has been used widely because it has provided a reliable means of abating sand production. These completions, however, have skin factors greater than 15, which increases with time as a result of fines migration into the packed area. In many cases, flow efficiencies were reduced by 70%, which affected well performance severely.

Introduction
The Temana field was discovered in 1962 and brought on production in 1979. The field is approximately 19 miles west of Bintulu in a water depth of approximately 96 ft. It consists of three hydrocarbon accumulations, Temana west, Temana central, and Temana east. The field has undergone a complex tectonic history and is highly faulted and compartmentalized.
The latest development is from the existing Platform A, which penetrates the Temana saddle, in the southeastern part of Temana central. The main reservoir target is the I-65 sand. The sand has a fining-upward log signature with a sharp base at the bottom of the sand. The sand contains light oil of approximately 41.1°API with reservoir pressure of 1,553 psi, average porosity of 26% (oil), and effective permeability of more than 1 darcy. The main drive mechanism of this reservoir is depletion drive, with weak-to-moderate aquifer support.
There are seven existing platforms and two additional production-processing-facilities platforms. Approximately 44 out of 74 of the existing oil-producer wells were completed cased hole IGP, and only two wells had premium screens installed in horizontal open holes. On the basis of well-test data for these wells for a similar type of reservoir, the average skin is 10 to 15 and increases to 20 to 30 after several years of production. The average productivity indices (PIs) of these wells ranged between 1 to 20 bbl/(psi-D). Investigation shows that the increasing skin and deterioration in production are a result of fines movements into the gravel-packed sand, and this was aggravated when water broke through.

Well-Design Considerations
The best standalone screen (SAS) available in the market should be selected for the new Temana wells, considering economics and well deliverability. The well-design team developed a workable solution to be used to minimize various risks. The SAS proposed is the direct wire-wrapped screen (WWS), which is a surface-filtered screen, where plugging tendency is minimized.