bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.
1980-89: Surviving Industry Turbulence
Authors: Donnelly John 
Published: February 2015

SPE made additional strides in internationalization and membership growth during the 1980s. Despite the free fall in oil prices that would mark a low point for the oil and gas industry during the decade—and lead to massive layoffs and restructurings—SPE not only survived, but in some ways thrived.
In 1980, membership rose 14% from the year before to 38,799. By now, a fifth of the society's membership resided outside the US and several regional meetings around the globe had developed. As membership and the diversity of members' technical interests grew, SPE was challenged to ensure that its meetings and publications were relevant to the specialist while appealing to a broad spectrum of disciplines. The scope of SPE's defined technical focus began to expand and include such interests as unconventional resources, geothermal energy, shale oil recovery, and facilities.
Ken Arnold, Senior Executive Vice President of AMEC Paragon and SPE's first Technical Director for Projects, Facilities, and Construction, was instrumental in getting SPE to offer more programs and services for facilities engineers. He chaired an ad hoc committee in the early 1980s in investigating SPE's relation to facilities engineering. "We presented to the SPE Board a plan outlining how we could provide more service to this group, with hopes of increasing its membership," Arnold said. "In those days, facilities engineering was not even considered a specialty; it was part of production operations. … One of the key recommendations that was implemented was the creation of a committee within SPE for facilities. It started to create programming for at least three or four sessions at each SPE Annual Technical Conference and Exhibition (ATCE), and that began to generate papers. Another thing we did was, when the SPE Production Engineering technical journal was first put together, we added a review chairperson and a technical editor committee for facilities topics to make sure that journal had facilities content."
Early in the decade, an ad hoc committee began to review the society's first Long-Range Plan, which had been adopted in 1976. It advised several changes that reflected the society's increased international presence and the importance and strength of local sections. The committee recommended adding director positions representing the Middle East, Asia Pacific, and South America, in addition to the one non-US director on the board from Europe. It proposed several other additions, including recommendations thatSection financial procedures include annual budgets and auditsThe society offer more continuing education support to sectionsSections establish their own newslettersSections create annual section awards and plans for officer rotationSPE become more involved in intersociety activitiesChanges should be made to SPE election procedures, including allowing members, for the first time, to select SPE regional director nominees through regional nominating committees.