bluuebunny/crossref_metadata_2025 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.
"Do Nothing": Technology's Toughest Competitor in the Upstream Oil and Gas Industry
Authors: Daneshy Ali
Published: February 2015

Guest editorial - No abstract available.
Wireless Transmission Ensures Crucial Data Delivery Remote From the Wellhead
Authors: JPT staff _
Published: February 2015

Technology Update - No abstract available.
Case Study: Value in Drilling Derived From Application-Specific Technology
Authors: Langley Diane
Published: February 2015

Case Study - No abstract available.
Integrated Tubular-Supply-Chain Management Reduces Cost
Authors: Hoffman Brad
Published: February 2015

Management - No abstract available.
Na Kika Intelligent Wells - Design and Construction
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90215, "Na Kika Intelligent Wells-Design and Construction," by C.D. Stair, SPE, Shell Intl. E&P Inc.; M.E.P. Dawson, SPE, Halliburton Energy Services Inc.; S. Jacob, SPE, Well- Dynamics Inc.; and D.B. Hebert, SPE, Shell Intl. E&P Inc., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Flow Assurance in Brazil's Deepwater Fields
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16687, "A Perspective View of Flow Assurance in Deepwater Fields in Brazil," by R.M.T. Camargo, M.A.L. Goncalves, J.R.T. Montesanti, A.B.R. Cardoso, and K. Minami, Petrobras, prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
Underbalance-Pressure Criteria for Perforating Carbonates
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86542, "Underbalance- Pressure Criteria for Perforating Carbonates," by S.T. Subiaur, Pemex, and C.A. Graham, I.C. Walton, SPE, and D.C. Atwood, SPE, Schlumberger, prepared for the 2004 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18-20 February.
Rock-Mechanics Aspects of Well Productivity in Marginal Sandstone Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 86468, "Rock-Mechanics Aspects of Well Productivity in Marginal Sandstone Reservoirs: Problems, Analysis Methods, and Remedial Actions," by Johan Tronvoll, SPE, Idar Larsen, Liming Li, SPE, Tore Skjetne, SPE, and Oyvind Gustavsen, SINTEF Petroleum Research, prepared for the 2004 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18-20 February.
Novel Perforating System Results in Improved Perforation for Sand Management
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86540, "Novel Perforating System Used in North Sea Results in Improved Perforation for Sand-Management Strategy," by Eivind Hillestad, SPE, and Paal Skillingstad, Statoil, and Kent Folse, SPE, Oyvind Hjorteland, SPE, and Janne Hauge, SPE, Halliburton Energy Services Inc., prepared for the 2004 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 18-20 February.
Overview: Tight Reservoirs (October 2005)
Authors: Mayerhofer Michael
Published: February 2015

The first thing that struck me while reviewing the list of papers for this feature was the broad range of what is considered to be a tight reservoir. Engineers working in the Barnett shale in North Texas deal with “supertight” matrix permeabilities of less than 1 µd (or nanodarcies). Engineers working in the Middle East may consider permeabilities of 30 to 50 md as tight. This is a range of more than six orders of magnitude. Of course, each environment has its own challenges and reasons for being considered tight.

In my opinion, there are three main challenges in the development of tight reservoirs.

- Quantifying the recoverable reserves and deliverability with the uncertainty of formation evaluation and reservoir characterization.

- Implementing the best well-completion, stimulation, and infill-drilling strategies to accelerate and increase ultimate field productivity.

- Combining the above issues must lead to economic success.

Certainly, the emergence of new technologies has improved reservoir-characterization, completion, and stimulation technologies. These technologies include better well-logging, well-testing, and core-analysis techniques; seismic interpretation; horizontal-well technologies; fracturing fluids and proppants; hydraulic-fracture diagnostics; and mapping technologies. High oil and gas prices of course, along with cost-reducing measures, contribute their part to the economic success.

The move toward more marginal and unconventional reservoirs presents significant challenges to technology, some of which have been overcome successfully. The Barnett shale, for example, has moved from a “curiosity” 10 years ago to the fifth-largest gas-producing reservoir in the U.S., and there is a feverish “hunt” for more Barnett-type analogs. Many tight reservoirs are in high-pressure/high-temperature (HP/HT) environments, which pose significant challenges for drilling, formation evaluation, and well completion. The fact that only a very small percentage of wells are drilled in HP/HT environments illustrates the significant economic hurdles. However, this resource base could be significant for meeting future natural gas demand in the U.S. and abroad.

Tight Reservoirs additional reading available from the SPE eLibrary: www.spe.org

SPE 94249 - “Development of a Low-Permeability Carbonate Reservoir by Use of Horizontal Wells in Mature South Umm Gudair Field in the Neutral Zone—A New Approach,” by Jha, M., SPE, Saudi Arabian Texaco/Kuwait Oil Co., et al.

SPE 94354 - “Adding Value Through Integrated Research To Unlock the Tight Gas Potential in the Rotliegendes Formation of North Germany,” by Gaupp, R., U. of Jena, et al.

SPE 94106 - “Developing the Obaiyed Tight Gas/Condensate Field, Egypt—A Case Study,” by Strating, E.H.H., SPE, Shell Intl. E&P, et al.
Evaporative Cleanup of Water Blocks in Gas Wells
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94215, "Evaporative Cleanup of Water Blocks in Gas Wells," by J. Mahadevan, SPE, and M.M. Sharma, SPE, U. of Texas at Austin, and Y.C. Yortsos, SPE, U. of Southern California, prepared for the 2005 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 17-19 April.

Gas flow into a wellbore can result in the evaporative cleanup of water blocks. This cleanup occurs primarily because the expansion of gas results in additional water being evaporated in the near-wellbore region. A study showed that the removal of water by the expanding gas leaves behind a saturation profile that is qualitatively different for low- and high-permeability rocks. As a result, the increase in gas relative permeability or the well productivity with time can vary substantially depending on the rock permeability and the well drawdown. A model was developed to determine the effect of evaporative cleaning on well productivity.

Introduction

Water blocks in low-permeability rocks clean up much more slowly than those in higher-permeability rocks because of the smaller pore sizes and consequent higher capillary pressures. Past simulations and experiments have reported the effect of gas displacement of water in the cleanup of water blocks in gas wells. Those studies showed that when the drawdown in the gas well is significantly larger than the capillary pressure, the cleanup is faster. However, when the drawdown and capillary pressures are approximately equal, which is the case in depleted tight gas reservoirs, the displacement of water by the incoming gas may not be sufficient to remove water from the near-wellbore region.

The flow of a fully saturated compressible gas through a water-saturated rock can induce evaporation. In past studies, the effect of evaporation from flow of gas has been neglected. This paper focuses on the evaporative cleanup of water blocks in gas wells where the drawdown is comparable in magnitude with the capillary pressure in the rock.

Recent research has shown that water-block removal takes place by two mechanisms. The first is a displacement of the water from the pores by the produced gas, followed by an evaporation regime that can last for many months. Higher drawdowns and solvent addition were shown to affect the relative permeability of the injected gas in the displacement and the evaporative regime and, therefore, the cleanup.

Mathematical Model

Fig. 1 shows the rate of liquid removal (brine) from limestone and tight gas sandstone cores by displacement and evaporation. At approximately 100 pore volumes (PV), the rate of displacement in limestone becomes smaller than the rate of evaporation, marking the onset of the evaporation regime. However, this demarcation between the displacement and the evaporation regimes may not occur at 100 PV at other temperatures or when the displaced liquid is volatile, such as methanol. In this study, brine was used as the displaced fluid, and the mathematical models for the two regimes were developed separately.
Technology Update: Real-Time Fluid Tracking Optimizes Treatment Design, Improves Strategy
Authors: JPT staff _
Published: February 2015

Collecting complete wellbore-temperature profiles during the placement of stimulation and diversion fluids has opened a new window to understanding and modifying matrix-stimulation, fracturing, and conformance treatments. Rapidly collected temperature profiles can identify precisely where fluids are entering the formation, allowing real-time optimization of the treatment through on-the-fly modification of the planned program. Such knowledge is necessary to improve stimulation-fluid placement across the entire treatment interval.

The Halliburton StimWatch service identifies stimulation-fluid placement on the basis of changes in fluid properties that introduce variations in temperature gradients as the fluid moves inside the wellbore. This type of analysis provides a detailed understanding of the quality of treatment as applied to the designated intervals through a quantitative assessment of downhole flow rates.

Monitoring Benefits

Historically, it has been difficult to evaluate the placement of stimulation fluids during a multizone treatment in real time. As a result, the zonal volume of injected fluid is based completely on geological-data interpretation; prejob fluid-placement simulators provide only a theoretical prediction of the injection profile. Unknown and unpredictable downhole events occur during stimulation treatments and can have significant impact on treatment results. To achieve successful stimulation treatments, it is important to obtain the following information throughout the job:Injection profile—which zones are being treated effectively and which zones are not being treated.Effectiveness of a diversion process.Status of squeezed zones.Location of natural fractures.

Service Description

The StimWatch service follows the treatment as it progresses downhole, monitoring distributed temperature profiles obtained by use of the fiber-optic OptoLog Distributed Temperature Sensing (DTS) system. As changes in wellbore temperature are caused by the injection process, this information is converted into downhole injection profiles for a qualitative indicator of fluid distribution across the pay interval. This is performed without the need for shut-in periods or extensive preconditioning of the wellbore.

The DTS fiber-optic-cable assembly can be deployed in a permanent or retrievable configuration. The assembly can be strapped to the completion casing or production tubing as a permanent installation. For retrievable scenarios in horizontal wells, coiled tubing can be used to position the assembly across the perforated interval.
Guest Editorial: Emerging Technology and Its Impact on the Industry
Authors: Farris Adam
Published: February 2015

It is no secret that oil fields today are more difficult to locate, evaluate, drill, and produce. In deepwater offshore projects, finding and drilling a prospect can take several years. Rig rates are up to U.S. $600,000/day and rising. A completed deepwater well can cost as much as $100 million.

Deep water is the extreme case, but consider onshore tight gas plays, where the permeabilities are in the microdarcies and extended-reach horizontals and complex completions are increasingly common. This pushes drilling and completion costs much higher. Other factors complicate the issue as well. There is a big gap in experience levels, and the engineering labor pool is dwindling. Management is preparing for the exit of many talented engineers, and as they leave, these innovators take with them lifetimes of hands-on experience. The industry challenge is this: How do we increase production with tougher problems to solve and the exit of experienced engineers and thought leaders? Technology has been touted as the saving grace for a long time, but is it the answer?

Our current industry leaders were in our shoes once. They were the emerging leaders, the up-and-comers with high aspirations and fresh ideas. Now they lead some of the most powerful companies in our industry—Anadarko, Chevron, ExxonMobil, Occidental, to name a few. We are all leaders because the success or failure of the oil and gas business depends on us. We have a responsibility to a lot of people.

Responsibility and accountability are inseparable from leadership, but think about another defining characteristic of a great leader. It is curiosity and the ideas and insight that accompany it. Then comes the hard part—follow-through and continual improvement. Technology by itself will not solve the industry's problems. The power comes from combining the valuable industry knowledge of our current leaders and making use of that information with tech-savvy successors. Leaders who continue to innovate and use advancements in technology to create additional business value—that is the future of our industry.

There is also a difference between using technology and being an early adopter. If you would not think twice about buying an iPod that came out last week, you are an early adopter. There is not a lot of fear associated with technology among young professionals because it has always been a part of their daily life. When applied to their careers, that technology-based viewpoint offers true business value.

Several examples from the past illustrate just how important technology and its advancements are. One interesting example is computer-aided design (CAD) systems and their applications. When CAD first appeared in the 1980s, very few engineers would apply it to projects. They tried to use it, but in the end, it was faster to draw their designs on paper.
Stimulation Effectiveness in Multilayered, Tight Gas Reservoirs: Pinedale Anticline Area
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100574, "Using Reservoir Modeling To Evaluate Stimulation Effectiveness in Multilayered ‘Tight’ Gas Reservoirs: A Case History in The Pinedale Anticline Area," by S.K. Schubarth, SPE, Schubarth Inc.; J.P. Spivey, SPE, Phoenix Reservoir Software LLC; and P.T. Huckabee, SPE, Shell E&P Co., prepared for the 2006 SPE Gas Technology Symposium, Calgary, 15–17 May.

Low-permeability, or "tight," gas reservoirs are being developed at an ever-increasing rate in the U.S. Currently, there are several tight gas plays in the U.S. where multiple intervals are commingled for economic viability. The Pinedale anticline completions pose a complex problem in determining the best stimulation method because as many as 22 separate stimulation treatments are placed in as many as 70 discrete sands over a 6,000-ft-thick interval. Evaluation is complicated by permeability variations that exceed two orders of magnitude and pore-pressure gradients that range from 0.22 to 0.83 psi/ft.

Introduction

Development of the Pinedale anticline in southwestern Wyoming has continued at an aggressive pace over the past several years. Massive hydraulic-fracturing (MHF) treatments are the only way to stimulate production from the tight gas sands present in this area to economically acceptable levels. Generally, each well requires between 14 and 22 MHF treatments to produce effectively from all potential pay intervals. Often, more than 2 million lbm of proppant is used per well, representing a high investment cost to the operator. The ability to evaluate the incremental production associated with the use of one proppant vs. another can have a significant effect on field profitability.

Data Analysis

Production and completion information from 11 wells with 172 fracture-treated intervals was included in this analysis. Production information was updated, and all 11 wells have at least two production logs, with one early in the well life. A detailed production history also was available for all wells for use in the reservoir-simulation evaluation. Six different proppants were used in the fracture treatments pumped.

Reservoir Simulation. For single-layer tight gas reservoirs, fracture and reservoir properties usually are estimated by analyzing production data. Methods for such single-layer analysis include advanced decline-curve analysis with constant-terminal-pressure type curves, type-curve matching with constant-terminal-rate type curves, and automatic history matching with a single-layer analytical reservoir simulator. Single-layer analysis methods may provide estimates of in-situ permeability to gas, fracture half-length, fracture conductivity, and drainage area, which are used in evaluating the success of a fracture treatment, selecting restimulation candidates, optimizing future fracture treatments, forecasting future performance, and estimating reserves.
SPE Presidents Look Back on 50 Years of Growth and Accomplishment
Authors: JPT staff _
Published: February 2015

The history of SPE is perhaps best told by the men and women who have guided it through the past 5 decades, from a primarily US offshoot of the American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME) to the worldwide technical and professional society it is today. JPT asked each of SPE's living past presidents to reflect on their terms—the highlights, the challenges, and the milestones.

Wayne E. Glenn, 1960

This year was an important one in the history of SPE. At a time when other professional societies were cutting back on services or increasing prices, SPE was adding services and holding dues the same and giving members more for their money. SPE established many important programs at this time. The Distinguished Lecturer Program was created in 1960 as was the new quarterly journal, SPE Journal, the society's first technical journal. Both were historic milestones for SPE.

SPE Executive Secretary Joe Alford and I began discussing the possibility of expanding SPE worldwide and starting up sections overseas. I had the Conoco plane at the time, and we traveled all over the world—to Europe, to Russia—to try to set up sections. We tried to find good people on the ground who were interested in SPE, and we met with government officials and left behind SPE literature. The funny thing was, often the person we left in charge of setting up the section, after the government saw how efficient and capable he was, would hire him away and put him on the government payroll and we would have to start again from scratch.

John C. Calhoun Jr., 1964

In February 1964, during the AIME Annual Meeting, I officially became SPE President, succeeding L.P. Wharton. Although SPE had become an autonomous unit of AIME in 1957, a period of transition still existed, which accounts for the February date for assuming the office of SPE President. This transition period, along with several other elements of change of concern to SPE, drove the society's agenda.

In my 1964 Presidential message, I took note of the fact that President Wharton had asked the question, "What are SPE's aims and obligations?" The very phrasing of this question reflected the relative youth of petroleum engineering and of SPE as a professional association, a situation that few in today's SPE world are aware of. I gave a threefold response to that question: our need to be a learning profession, to seek out and nurture new members of the profession, and to enlarge our awareness of a role for SPE with respect to the broader issues of our general society. When, in the fall of 1963, as President-elect, I had outlined these views, the Oil & Gas Journal reported it as a three-point education program—the education of SPE members, the education of those who will become petroleum engineers, and the education of the public at large. These were the challenges that SPE faced in becoming a truly separate and higher-quality professional association that represented a fully recognized branch of engineering.
A Celebration of a Remarkable Half-Century
Authors: Campbell John M.
Published: February 2015

I joined the Petroleum Branch of the American Institute of Mining and Metallurgical Engineers in 1952 as member number 2552. What a fortunate move. The "Big Bang" period of petroleum technology was in progress and, like our universe, it has continued to expand at an ever increasing rate. It was both a chaotic and exhilarating time. I had become a part of what was as much a challenge as my previous work on the Manhattan Project during World War II. There were so many folks doing such great things and rising to the challenge.

Of course, there had been a long period of innovation preceding it that effectively began with the work of John Franklin Carll in the 1870s (for whom a major SPE award is named). As is always the case, technological innovation was triggered by the growing needs of the industry. At the end of the 1940s, a very basic foundation had been established to meet the needs of the industry. This involved primarily the drilling of rather shallow wells that had a short payout, with the primary surface processing being the separation of the oil from the water, solids, and gas. Because of the depth, the producing pressures were low and much of the gas not required to operate the lease was flared.

Most of the technology had been adapted from other industries. Reservoir measurements and analysis were rudimentary. The electric log invented by the Schlumberger brothers in 1918 had been adapted for petroleum reservoir use in the early 1930s. Also in the 1930s came other developments such as pressure testing, a material-balance approach for analysis, and improvements in the tools used to drill and complete wells.

After the end of World War II, demand for energy exploded and, as usual, the industry responded. But this required the exploration and exploitation of deeper reserves in less friendly environments. What was needed was new technology, quickly. One example was the development of reserves in the "swamps" of southern Louisiana and the shallow waters just offshore. The industry sought technology that would allow this to occur in a favorable economic manner. The front-end costs increased markedly, and a national market for natural gas complicated production strategies. Better methods for locating potentially profitable drilling sites were needed. Technology that previously had been a secondary concern in many circumstances now became a critical part of the decision process.