bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techbits: China Workshop Examines Fractured Carbonate Reservoirs
Authors: JPT staff _ 
Published: February 2015

Techbits
An SPE Applied Technology Workshop (ATW) on “The Characterization of Effective and Efficient Development of Fractured Carbonate Reservoirs” was held 15-18 June 2014 in Nanjing, China. Participants reviewed recent advances in exploration and production and the technical challenges presented by these reservoirs.
A variety of carbonate reservoirs exist worldwide, mainly paleokarst reservoirs. Because of various scales, poor continuity, strong heterogeneity, accumulation in vugs and fractures, and complex flow behaviors, the efficient development of fractured carbonate reservoirs is quite challenging.
Li Yang, cochairperson of the workshop, opened the session and ATW Chairman Wang Zhigang delivered one of two keynote speeches. He focused on the challenges and current activities of a key carbonate reservoir, Tahe, that he said represented the theme of the ATW. Usman Ahmed, also a workshop cochairperson, introduced the second keynote speaker, Christine Ehlig-Economides. She recalled an ATW a decade ago that also had focused on the Tahe reservoir. She set the stage for a discussion on how much the industry has advanced and the challenges that lie ahead.
In his keynote speech, Wang of Sinopec described the technical challenges and techniques used at Sinopec’s Tahe oil field in western China. The Tarim basin is the company’s largest carbonate play, with proven reserves of 1.3 billion tons and depths of 5300 m to 6300 m. The oil and gas accumulated in pores, vugs, and fractures of severe heterogeneity and depth make it difficult to predict and describe reservoir characteristics, he said.
Carbonate reservoir characterization and evaluation techniques have been developed that have improved the predictability of the carbonate reservoir and its distribution and have increased drilling success, he said. In the Ordovician carbonate reservoir of Tahe, a series of techniques such as paleokarst landform categorization, paleokarst cycle division, hydrocarbon accumulation period analysis, logging for reservoir identification, and evaluation have been implemented. In addition, massive acid fracturing (high pumping pressure, high injection rate, large scale) has become a major technique for development at the field.
In sum, the technical challenges are:
Ultradeep, highly heterogeneous reservoirs with low-resolution seismic data make it difficult for reservoir prediction.
The form of fractures and vugs and oil and gas accumulation in such reservoirs make reservoir modeling difficult.
A variety of reservoir fluid systems exist, which lead to a complex oil-water distribution. Current simulation techniques need to be further improved.
Severe channeling and breakthrough were detected after waterflooding was applied. Further research is needed to improve waterflooding, residual oil characterization, and water-control techniques.
Drilling activities are extremely challenging and costly. Drilling technology needs to be further developed or modified.
As Scarcity Hits, Water Tech Flows In
Authors: Jacobs Trent 
Published: February 2015

Water Treatment
Although the oil and gas boom in the United States owes much of its success to the abundance of cheap sources of fresh water, the status quo is beginning to change. Groundwater remains the main source of water for most onshore exploration and production companies; however, they are increasingly investing in produced and flowback water- treatment technologies. Many of the same companies are also turning to brackish water sources in places where freshwater aquifers are becoming depleted, such as the Permian Basin that spans west Texas and eastern New Mexico. Brackish water, sometimes called fossil water, has less salt content than seawater, making it cheaper to treat, and is typically found in the same areas where hydrocarbons are developed.
The Fasken Oil and Ranch in Midland, Texas, relies on produced-water recycling and brackish water for nearly all of its oil and gas operations at its primary operating area. In August, a larger operator in the area called to buy produced water from Fasken, said Jimmy Davis, operations manager at the family-owned oil company.
The friendly request exemplifies the increasingly desperate water situation that oil companies are facing in the Permian Basin, one of the most productive onshore areas in North America. “They are in a fix for water,” Davis said. “I am starting to hear that over and over. What we are doing out here as an industry is using water to frac, and we are in a drought-stricken area so you have to find other means than fresh water to meet those needs.”
Based on the number of inquiries and activity that he is seeing from neighboring companies, Davis said he predicts that over the next few years, a majority of Permian Basin operators will turn to brackish and produced water as their primary sources. “If you are going to continue to frac like we are, that is what you are going to have to do to sustain it,” he said.
According to a market analysis report by Houston-based PacWest Consulting, onshore oil and gas companies in the United States spent USD 20.1 billion last year on water-management services. While only 4% of the spending was for water treatment, if projections hold true, then this year will mark the turning point. The report said that water treatment represents the smallest yet fastest growing segment of the water-management market with a forecast of 23% growth each year to USD 1.3 billion by 2016. “Prevailing drought conditions and long-term sustainability of freshwater sources is expected to steadily increase demand for treatment services,” the report concluded.
University R&D Around the World: Part 2
Authors: Betz Jack 
Published: February 2015

R&D on Campus
As the task of finding and producing hydrocarbons becomes more difficult, complex, and costly, the number of universities focusing on finding solutions has risen. Whether the frontier is heavy oil, deep water, or remote locations, efforts within academia are under way to solve the next generation of technical challenges confronting hydrocarbon E&P operations. Because many noteworthy research and development (R&D) efforts exist at universities all over the world, the intent of this article is not to cover all of them but to present a sampling from many geographical locations. Part 1 of this two-part series appeared in September’s JPT.
The University of Tulsa (TU) was formed in Tulsa, Oklahoma, in 1907, when the boards of Kendall College and McFarlin College made the decision to merge the two institutions. TU has offered academic degrees in petroleum engineering since 1932 and has a research and development (R&D) program dating back to 1965, when property and buildings were donated by Humble Oil and Refining Company, creating TU’s north campus, which is devoted entirely to oil and gas.
TUDRP
To support its research, the university formed the Tulsa University Drilling Research Program (TUDRP) consortium, which currently has 18 industry partners. TUDRP aims to improve drilling operations while reducing costs and the number of safety and environmental incidents.
According to principal investigator and director of TUDRP, Stefan Miska, the center has completed 153 research projects since 1968; TUDRP’s 2014–15 programming brochure lists 13 active research projects.
The center is operated by 27 personnel—including senior-level researchers, nonresearch employees, and 16 advanced-degree candidates who assist in conducting the studies.
Combining Pressurized-Mud-Cap-Drilling and Early-Kick-Detection Techniques
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165893, ’Combining Pressurized-Mud-Cap-Drilling and Early-Kick- Detection Techniques for Fractured Formations Overlying a High-Pressure Reservoir in Offshore Kalimantan,’ by Benny Benny, SPE, Andri M. Hidayat, Ardia Karnugroho, SPE, Julius Sosa, and Julmar Shaun S. Toralde, SPE, Weatherford, prepared for the 2013 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 22-24 October. The paper has not been peer reviewed.
Pressurized-mud-cap drilling (PMCD) and early kick detection (EKD) are two unconventional drilling techniques that have been used widely individually, mostly in relation to closed and pressurizable systems and to managed-pressure-drilling (MPD) applications. The techniques, however, are seldom used together as an integrated setup. This paper describes a synergized PMCD and EKD setup and the field deployment where it was used to drill a well successfully offshore Kalimantan, Indonesia, that had a high-pressure formation below a zone prone to severe circulation losses.
Introduction
Many drilling problems offshore Kalimantan involve lost-circulation problems and unintended influxes. Drilling conventionally through fractured and extremely vugular carbonate formations, which are prone to severe lost-circulation problems, can lead eventually to well-control situations. Aside from that, significant time and resources are required to cure the losses before conventional drilling can be continued. In addition, of 1,000 ft of carbonate formation drilled offshore Kalimantan, the fractures often are present in layers, which will multiply considerably the time and resources spent each time severe or total loss is encountered. One of the more well-known ways to mitigate this problem is implementation of the variant of MPD called PMCD, which enables the operator to drill through the fractured formation safely and efficiently.
Meanwhile, also in offshore Kalimantan, most of the zone that resides just several feet below the fractured carbonate formation is highly pressurized gas reservoir. Drilling conventionally through such a pressurized zone exposes the operation to greater risk because of a lack of precision in detecting any influx or outflux during the drilling operation. A better method for detecting influx is the use of a flowmeter to monitor the flow from the well. The most common flowmeter used is a Coriolis mass flowmeter (CMF). Although the CMF has the advantage of great precision in measuring flow rates, the conventional setup lacks accuracy because the system is open to the atmosphere. A further improvement is to use it in conjunction with the MPD system to create a closed-loop system that will increase accuracy. This is the EKD system.
Evaluation of Strategies for Enhancing Production of Low-Viscosity Liquids
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169479, ’Evaluation of Strategies for Enhancing Production of Low-Viscosity Liquids From Tight/Shale Reservoirs,’ by G.J. Moridis, SPE, Lawrence Berkeley National Laboratory, and T.A. Blasingame, SPE, Texas A&M University, prepared for the 2014 SPE Latin American and Caribbean Petroleum Engineering Conference, Maracaibo, Venezuela, 21-23 May. The paper has not been peer reviewed.
Production of low-viscosity liquids, including condensates, from tight reservoirs such as shales is severely restricted by the ultralow permeability of such formations, limiting production to a very small fraction, usually less than 5%, of the liquids in place. In this study, the authors evaluate, by means of numerical simulation, several possible strategies to enhance low-viscosity- liquid production from such reservoirs. The objectives of this effort are to remove from further consideration strategies that hold limited promise, and to identify strategies that have potential for further study.
Introduction
The remarkable success of gas production from tight reservoirs and shale reservoirs has not been matched by similar progress in the production of relatively- low-viscosity liquid hydrocarbons (including condensates) because of the significant challenges to liquid flow posed by the ultralow permeability of such reservoirs.
Increasing the recovery of liquids from these ultralow-permeability systems even by 50% over its current very low levels not only will increase production and earnings but will have considerable wider economic implications because the increased recovery will affect reserves and the valuation of companies. The authors’ effort aims to address this issue by using numerical simulation to investigate a wide range of possible strategies for improved liquid production from tight/shale reservoirs. In essence, this is an attempt to provide a baseline mechanistic study that deploys some state-of-the-art tools in reservoir modeling. The paper focuses on determining the baseline performance of various key production methods that are considered standard in the attempt to produce low-viscosity liquids from tight reservoirs and shale-oil reservoirs. These include recovery by use of displacement methods, viscosity-reduction methods, enhanced reservoir stimulation, and combinations thereof.
For a discussion of the simulation code and the underlying fundamental equations of flow and transport, please see the complete paper.
Fractured-System Description and Subdomain Representation
Subdomains. The fractured system in producing tight gas reservoirs and shale-gas reservoirs can be described as a set of interacting subdomains.
Energy 360: Cutting Rocks - With A Huge Sense of Purpose
Authors: Haldorsen Helge Hove 
Published: February 2015

President's column
The Yin and the Yang of E&P - No Shadow without Light
What does a sense of purpose have to do with anything, you may ask? The exploration and production (E&P) business is about rocks, rigs, and remotely operated vehicles (ROVs). It is about compound average growth rates (CAGR), return on average capital employed (ROACE) and great health, safety, security, environment, and social responsibility (HSSE-SR) performance. It is not about soft stuff such as a sense of purpose, passion, and creativity, or is it? I am going to try to convince you that it is. The two are the yin and the yang of E&P or the hard and the soft side of E&P. After 36 years in the industry, I have come to realize that the hard side of E&P actually is soft, since delivery depends 100% on the human element and that the soft side is the hardest to get right. The truth is you cannot have one without the other (Fig. 1). If a sense of purpose and passion are two key components of light, then strong growth and a healthy return on investment are the resulting shadows. You cannot have the shadows without the light.
The Giza Pyramids, 1500 BC
If we asked a craftsman cutting rocks next to one of the three ancient Giza pyramids being built around 1500 BC, “Excuse me, sir, are you cutting rocks?” His answer would have been, “No, I am not just cutting rocks, I am building a pyramid.” The difference is the sense of purpose associated with what he was doing. He was involved with something greater than himself and his own self-interest that inspired and energized him in his work. With a sense of purpose, suddenly, what you do for a living is not just a job. It is much more than that. It is about making a difference. It is about changing the world.
240,000 New Energy Customers Every Day
Today, we have 7.2 billion people on the planet. Every hour, the Earth’s population grows by some 10,000 new energy customers and by a quarter million every day. After just a week, we have generated a new city with a population of 1.5 million with every new citizen wanting one thing in particular: energy. This is because our new world citizens want the same as us: electricity at home, heating and cooling, mobility, and transportation. (Note: Approximately 1.3 billion people are still without electricity and, according to the World Bank, only 24% of Africans have access to electricity.
Visualizing Low-Salinity Waterflooding
Authors: Sanderson Colin , Sohrabi Mehran 
Published: February 2015

Technology Update
Low-salinity waterflooding has recently attracted considerable interest from governments, researchers, and oil companies, who are evaluating the method’s potential to increase oil recovery. While laboratory work and field tests have indicated that low-salinity waterflooding can have positive results, and implementation of the technology is planned, there are still a number of challenges and uncertainties related to the technique. It is generally accepted that the effects of low-salinity waterflooding are caused by wettability alteration, but the processes involved are still not fully understood.
Heriot-Watt University has been conducting research to investigate the mechanisms of interactions between low-salinity water, crude oil, and porous media at reservoir conditions. Industry support for the work was secured through Industry Technology Facilitator (ITF), and professor Mehran Sohrabi, director of the Center for Enhanced Oil Recovery (EOR) and CO2 Solutions at the university, is leading the project team.
Low-Salinity Water Injection
Waterflooding improves oil recovery by displacing oil, and injection water is usually taken from the nearest available source (which is seawater for most offshore fields). The first effects of low-salinity water injection were published in the 1990s, when work at the University of Wyoming indicated that injecting water with a total dissolved-solids content of less than 5,000 ppm resulted in a higher oil recovery than that attained by injecting high-salinity water such as seawater. Since then, a number of studies with varying results have been published, and the recovery benefits described are likely to be field-dependent.
Low-salinity waterflooding has a number of potential benefits. It has relatively low costs compared with other techniques. It can be implemented in ongoing and new waterflood projects onshore and offshore and has shown potential for sandstone and carbonate reservoirs. In addition, it can be used alone or in conjunction with other EOR techniques, e.g., polymer injection, as a technology enabler. It also can alleviate problems associated with conventional waterflooding, such as scale formation and souring.
Borehole Imaging Technology Visualizes Photorealistically in Oil-Based Muds
Authors: Laronga Robert J. , Shalaby Ehab 
Published: February 2015

Technology Update
To estimate reserves, optimize well recovery, and place future development wells more accurately, operators require increasingly detailed understanding of complex oil and gas reservoirs. High-resolution geological data from the borehole— core samples and wireline microresistivity images—are essential to fully characterize reservoir architecture, guide and constrain reservoir models, and make timely decisions with precision and confidence.
In unconventional resource plays, for example, geologists need to observe complex natural fracture systems, measure fracture density and direction, determine in-situ stresses, and calculate pressures required to initiate and propagate optimal hydraulic fracturing. In high-cost deepwater environments, exploration teams need to interpret a wide variety of sedimentary facies. Reservoirs often consist of thinly laminated sands or channels, which demand high-definition methods for visualization and interpretation. Typically, deepwater formations exhibit very low resistivities— from 1 ohm-m in shales to as low as 0.2 ohm-m in water-bearing sands.
Operators often use whole cores to identify subtle sedimentary facies, but cores can be expensive and time-consuming to acquire. Thus, core samples are usually obtained only in select wells and in the most critical intervals. The resulting lack of geological detail can adversely affect reservoir analysis, interpretation, and modeling.
On the other hand, microelectrical borehole images can be acquired continuously over the openhole interval at any depth or in any formation, with relative ease. Until recently, high-definition borehole imaging has been possible only in electrically conductive water-based muds (WBM). However, most deepwater wells and many unconventional shale wells today are drilled with high-performance, nonconductive oil-based muds (OBM).
Legacy OBM borehole imaging tools, which were introduced in the last decade, are a significant technical advancement over the preceding dipmeter tools but still exhibit certain limitations. For example, spatial image resolution in OBM is nowhere near the quality obtained from WBM imagers. The lack of circumferential coverage of the borehole leaves large gaps that must be filled by inference.
Pushing the Frontier through Wellbore Strengthening
Authors: Jacobs Trent 
Published: February 2015

Drilling Fluid Technology
Making hole has become a more difficult and complex operation as operators move into untapped horizons, especially deepwater and unconventional fields. It is this increased difficulty that is driving a growing number of companies to invest millions of dollars in advanced materials that seek to make drilling wells easier. The technologies many are working on involve not mechanical systems, but advanced chemistry and physical science. Some are using nanoparticles and others are reworking older technologies by adding new substances, all in an effort to make the undrillable drillable.
Those reaching for this prize include teams of university researchers, young technology startups, and established firms that are buying intellectual property from others so they can join the race. Different groups are designing drilling-fluid additives and other materials that they claim make unstable wellbore walls stronger by preventing and sealing fractures as the drill bit eats its way down to the pay zone.
The importance of these wellbore-strengthening objectives is well understood by drillers who have suffered sudden losses of drilling fluids into the rock formation through fractures, which can lead to gas kicks and catastrophic blowouts, or those who have had to deal with stuck pipe because of a collapsed borehole. For petroleum engineers, preventing these problems with new technology means they can design simpler, cheaper, and safer wells with fewer casing strings. For the boardroom, wellbore strengthening means executives can promise better returns and higher flow rates to investors because large-diameter casing strings can be placed into the production zone. And for the industry in general, wellbore strengthening means wells that many consider too dangerous or too hard to drill may soon become tamed.
Clay-Stabilizing Nanoparticles for Water-Based Drilling Fluids
In April, downhole chemical technology provider Flotek Industries acquired water-based, drilling fluid-additive technology from ARC Drilling Fluids. Flotek hopes to use the technology, which it markets as Microsolutions, in areas where using oil-based drilling fluids have traditionally been the only option. Drilling fluids that use water as a base are far cheaper than oil-based fluids, making them more desirable, but oil is less reactive with many rock formations.
Wellbore Strengthening: The Mechanical Option
Before many of the new chemical and nanoparticle technologies for wellbore strengthening arrived to the marketplace, casing while drilling (CWD) was used for more than a decade to mechanically achieve the same end. Weatherford International and other service companies have developed multiple technologies for CWD, as well as the similar method of liner drilling (LD). With CWD, the casing is the drillstring, and with LD, the liner is the drillstring.