bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Technologies Enhance Efficiency of Horizontal, Multistage Fracturing
Authors: Themig Dan 
Published: February 2015

Technology Update
Significant differences in completion philosophy are emerging within our industry. Even companies that practice a factory mentality (one size/method fits all) are beginning to see that the “sledgehammer approach” to hydraulic fracturing may not be the most effective in draining horizontal wells in resource plays. For several years, we have seen massive increases in fluid volume, pumping rate, total proppant volume, and pumping time to increase recovery. We have seen through microseismic as well as fracturing into offset wells, that we are able to create massive and extremely long hydraulic fractures. Yet, when effective fracture length is calculated, the results are extremely disappointing. It only makes sense that “more is better.” However, after years of steadily increasing job size, stage number, perforating strategy, proppant volume, and lateral length, the only one that stands out as consistently improving recoveries is that more stages are required to effectively drain microdarcy permeability rock (Rankin et al., 2010).
What We Have Learned
Building an understanding of shale gas, unconventional gas, tight carbonate reservoirs, and more recently the renewed emphasis on oil and high-liquid gas formations has not been easy. Perhaps this is because of the extremely rapid pace of development and the acceptable economics of many projects in North America and throughout the world. Also, the diversity of applications for horizontal, multistage fracturing has made it more difficult to pin down best practices. As a massive body of data develops, a number of things have become clear. First, when equivalent stage numbers and proppant volumes are considered, open hole generally seems to outperform cased hole by 25% to 70% in production (Fig. 1, Edwards et al., 2010; Snyder and Seale, 2010). Second, the number of stages required to effectively drain microdarcy permeability rock is extremely high. Just a few years ago, performing 20 stages seemed too high to consider. Current stage numbers are often double that. Third, today’s common plug and perf practices—even at high densities—may not be sufficient to drain shale gas or tight oil, even after 15 years of depletion time (Quirk, 2010). Reservoir modeling indicates that evenly spaced fractures would effectively drain today’s reservoirs in North America. The actual production data, however, indicates otherwise.
Proppants: Where in the World
Authors: Beckwith Robin 
Published: February 2015

With the rise in hydraulic fracturing over the past decade has come a steep climb in proppant demand. Global supplies are currently tight. The number of proppant suppliers worldwide has increased since 2000 from a handful to well over 50 sand, ceramic proppant, and resin-coat producers. The estimated amount of proppant used has grown tenfold since 2000, when little more than 3 billion lbs was supplied, according to research by PropTester and Kelrik. Circumstances appear favorable for those seeking to enter the market.
However, gearing up to take advantage of these propitious conditions represents a daunting task, requiring coordination of complex logistics, material resources, and processing knowledge, as well as a substantial capital investment in processing and material handling facilities.
The price proppant manufacturers can charge must be figured in to the overall cost of producing a well, which in the Bakken, for example, can be approximately USD 6 million, with proppant representing about 5% of well costs. Since a majority of proppant is currently used in fracturing unconventional gas wells, depressed natural gas prices tend to keep a cap on the prices proppant suppliers can demand.
However, as hydraulically fractured wells proliferate, a growing body of data is continually being generated to aid in the creation of targeted fracture stimulation plans, with more highly engineered stages—boosting the demand for greater volumes of proppant—being performed per well to maximize production. For example, a typical Barnett Shale well would in the early 2000s have consumed approximately 300,000 lbs of proppant. The longer horizontal wells drilled today, produced with often 20 or more stages, might consume 3 to 5 million lbs.
Still, proppant supplier margins are relatively slim, requiring the steady, high-quality production and distribution of large volumes to sustain a profitable enterprise.
Proppants: Earth to Earth
The journey of an individual grain or bead of proppant is a circular one, making its way from its origins as a substance mined from the Earth to its final destination deep within the Earth in the far reaches of the filigree-like or dendritically shaped fractures emanating from the long horizontal borehole. It is the only substance operators want to remain downhole following a successful hydraulic fracturing treatment and performs the vital function of propping open the fractured formation to promote the economic flow—or conductivity—of hydrocarbons in the ensuing months and years over the well’s productive life.
The primary order of business for a proppant facility, therefore, is choosing the optimum location—preferably one close to both raw material supply and end-user. The immediate proximity of railcar and possibly barge transport is critical, as well as a good road system and the availability of a reliable trucking fleet.
Well-Integrity Issues in Malacca Strait Contract Area
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 129083, ’Well Integrity Issues in Malacca Strait Contract Area,’ by Weka Janitra Calosa, SPE, and Bambang Sadarta, SPE, EMP Malacca Strait, and Ronaldi, WCS Indonesia, originally prepared for the 2010 SPE Oil and Gas India Conference and Exhibition, Mumbai, 20-22 January. The paper has not been peer reviewed.
The Malacca Strait contract area is east of Sumatra Island between Sumatra and the Malaya Cape. This area started oil production in the early 1980s, and consists of 175 onshore and offshore oil wells spread over five fields. A 7.9 Richter scale earthquake occurred on 12 September 2007. Two days later, during a snubbing unit service on Well K-02, the 95/8-in. casing suddenly dropped down 6 ft. It was believed that the area had been affected by the earthquake. Following the incident, the well-services team inspected Well K-02 and found that it had an integrity problem.
Introduction
Following the Well K-02 incident, historical records were examined, and it was found that the Well K-02 incident was not the first. Several well incidents had been reported previously with significant impact and potential for serious accidents. This created the awareness that there might be a wider issue, and a comprehensive well-integrity study was initiated to obtain better insight into the well-integrity situation for all wells within the block. The scope of the study was the following.
To evaluate the well-integrity status of all wells.
To review the possible causes of the well-integrity problems.
To generate workable engineering recommendations to extend the economic life of the production wells safely.
To include well-integrity considerations in future well-planning and operation procedures.
To build a comprehensive database of well-integrity condition and solutions.
Well Integrity. Well integrity, is defined as the application of technical, operational, and organizational solutions to reduce the risk of an uncontrolled release of formation fluids throughout the life cycle of a well. There are various facets to well integrity, including accountability/responsibility, well operating processes, well service processes, tubing/annulus integrity, Christmas-tree/wellhead integrity, and testing of safety systems. Well barriers are envelopes of one or several dependent well-barrier elements to prevent fluids or gases from flowing unintentionally from the formation into another formation or to surface. Interrupted barrier elements are related to well integrity and are crucial from the point of view of safety, but are also important concerning production regularity and cost. Lack of well maintenance may interfere with the well-barrier concept.
Well-Integrity Field Survey
The survey was conducted to compile a well-integrity database based on the status of the well barriers, using the following basis for evaluation.
History Matching With Learned Sparse Dictionaries
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 133654, ’History Matching With Learned Sparse Dictionaries,’ by Mohammad-Reza M. Khaninezhad, Behnam Jafarpour, SPE, and Lianlin Li, Texas A&M University, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.
History matching of heterogeneous hydrocarbon reservoirs is carried out to construct predictive reservoir models. Estimating individual-gridblock heterogeneous-reservoir properties from limited static data and spatially averaged dynamic-production measurements inherently leads to an ill-posed inverse problem that can have several nonunique solutions. To achieve solution sparsity, an iteratively reweighted-sparsity regularized least-squares algorithm is used to combine and weigh a small subset of relevant model elements selectively from a learned dictionary that explains the observed data.
Introduction
History matching of hydrocarbon-reservoir models is required to integrate production data that constrain uncertain previous descriptions of model parameters (i.e., spatially distributed petrophysical properties). The main goal of history matching is to construct updated models capable of predicting future performance of the reservoir more accurately. Reconstructing petrophysical properties is a challenging inverse problem because of data scarcity and because these properties are heterogeneous. When spatial discretization of the forward-simulation model is used to describe unknown spatial parameters in history matching, the problem typically becomes ill posed because the number of unknown parameters overwhelmingly exceeds available observations. Consequently, several nonunique solutions can exist that respect available observations but exhibit different spatial continuity and flow predictions. Several techniques can regularize ill-posed history-matching problems. Usually, regularization involves incorporating additional prior assumptions to eliminate implausible solutions and improve the stability of solution algorithms.
Reparameterization
Reparameterization of the original spatial problem is a regularization approach for ill-posed inverse problems in which a reduced number of parameters is used to approximate the unknown-petrophysical-property maps. Reparameterization is facilitated when reliable a priori information about structural attributes of the solution is available.
Mathematical transformations provide an effective reparameterization approach when the properties of the unknown parameters are exploited better in the transform domain. For example, principal-component analysis (PCA) is effective in reparameterizing correlated parameters by elimination of their correlation (redundancy). Other popular transform-domain reparameterization methods that have compression properties include the discrete-cosine transform (DCT) and the discrete-wavelet transform (DWT).
Real-Time Field Monitoring To Optimize Microbe Control
Authors: Keasler Vic 
Published: February 2015

Technology Update
Microbial growth in oil and gas systems can cause numerous problems that result in production downtime, lost revenue, and safety concerns. Unfortunately, microbial populations are ubiquitous in many oil and gas production zones and minimizing their impact is challenging. The most common effects of microbial growth are corrosion, hydrogen sulfide (H2S) production, and biofouling.
The ability to minimize the negative impact of microbes is confounded by the current field monitoring technology, which is unable to detect many of the organisms. These monitoring technologies are culture-based, meaning that organisms must be grown in culture to be detected and quantified. It is well documented in many systems that less than 1% of the total organisms present are culturable. In addition, the culture-based methods commonly take days or weeks to produce a result. Thus, operators must wait a considerable time before taking control measures, and the impact of microbial populations can increase during the long period of undetection.
New Development in Monitoring Method
Two essential parameters for any new field monitoring technology are the ability to obtain a result in real time and the ability to detect all organisms, not just the ones that can be grown in culture. The industry has evaluated several of these technologies over the years, including a first-generation adenosine triphosphate (ATP) assay in which the level of ATP is used to measure the number of actively growing microbes in a sample.
ATP is the molecule used by cells to drive any process that requires energy. This includes metabolism, protein translation, DNA repair, and cell division. Although there are differences in the absolute quantity of ATP in different species or organisms, it is assumed that actively growing bacterial cells hold relatively similar amounts of ATP, and a calculation has been determined to quantify microbial cell numbers based on a measurement of ATP.
The major challenge of using this technology in oilfield systems is that the enzymatic assay used to quantify ATP is very sensitive to the quality of the fluids tested. This means that many oilfield fluids such as oil, emulsions, produced water with significant solids, high-salinity fluids, and fluids contaminated with certain chemicals would not yield meaningful results. As an example, the first-generation ATP test was not generally accepted by oilfield operators and has been little used. However, a second-generation ATP test that addresses the concerns has been developed recently. Specifically, additional steps were developed to enable accurate testing of fluids that contain oil, high salinity, residual chemicals, and solids. This technology also meets the other necessary criteria—real-time results and detection of all microbes, not only those that grow in culture.
Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor, and Engineer Should Know About Hydraulic Fracturing Risk
Authors: King George E. 
Published: February 2015

Management - This is an excerpt from SPE 152596.
The use of horizontal wells and hydraulic fracturing is so effective that it has been called “disruptive.” That is, it threatens the profitability and continued development of other energy sources, such as wind and solar, because it is much less expensive and far more reliable. Not only that, but compared with coal, natural gas produces only half the carbon dioxide and almost no sulfur, nitrous oxides, or mercury.
Those demonstrable benefits over both traditional and alternative energy draw monetary and political attacks. Some university and media reports have focused on two main environmental concerns about using hydraulic fracturing to recover shale gas:
Groundwater and/or surface-water contamination by methane or chemicals
Escape of methane gas to the atmosphere
These risks come from well construction, transportation of chemicals and fluids to the well site, and operation of the wells and the gas-transport system. This paper is an abbreviated analysis of a larger document on factual information about the purported risks of hydraulic fracturing:
1. Deep-well hydraulic fracturing does not travel through the rock far enough to harm fresh-water supplies. Thousands of field-monitoring tests and millions of fracturing jobs have confirmed this point.
2. In the deep, properly constructed wells that produce most US shale gas, the chance of even minor water contamination from fracturing chemicals is less than one event in a million fracture treatments, based on statistical analysis. When compared with the frequency of pollution from chemical dumps, acid mine drainage, general manufacturing, oil refining, and other energy- or product-producing activities, natural gas from conventional and unconventional sources generates more energy with the least impact and fewest problems.
3. Even as underground fractures grow (mostly outward with limited upward and downward growth), the total fracture extent remains thousands of feet below the deepest fresh water sands. The height of any fracture is limited by rock stresses, leakage of fracturing fluids within the target fracturing zone, and the hundreds of natural rock barriers that border the shale zone. Typical fracture height is 100 to 300 ft and separation between the top of the fracture and the deepest fresh water sands ranges from 3000 to over 5000 ft.
4. Water contamination due to spilled industrial chemicals occurs rarely and even less so for fracturing chemicals and comes exclusively from careless road transport, on-site storage and surface mixing, or well construction. These failings can be addressed successfully with existing technology and effective regulations. It is interesting to note that the states with the fewest problems are those with strong state regulations. Appropriate regulations already exist in most producing states and work very effectively to protect the environment.
Companies Strive To Better Understand Shale Wells
Authors: Rassenfoss Stephen 
Published: February 2015

Fracture science
While drilling more than 2,000 wells in the Fayetteville Shale, Southwestern Energy systematically established standards for drilling and completing wells.
Based on the numbers, the company mixes slickwater with a 50:50 mix of fine and coarse grains of sand when fracturing wells in the shale formation. The proppant mix was chosen after a field test comparing 26 pairs of wells where everything, but the sand used, was the same.
It found that generally the 50:50 mix of coarse-grained sand and fine-grained proppant (100 mesh and 30/70 mesh) was more productive than all coarse-grained (30/70 mesh). There was little benefit shown in the five pairs of wells using all of one or the other.
But there were some wells where a mix was used with lower production than the paired well using all coarse-grained sand. Those five with lower output lost less—down an average of 15%—than the 16 wells that benefited from the mix—up an average of 27%.
In the past year, Southwestern has increased its research and laboratory capacity to learn why such things as proppant size matter. “We are now trying to understand what the mechanism really is,” said Karen Olson, completions expert for the Fayetteville Shale at Southwestern, in a presentation at the recent SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas.
Southwestern has been a leader in the way things are done in the shale business. It discovered the second major shale play because of an anomaly—a well had produced many times more gas than it should have based on the size of its reservoir. A small group in exploration ultimately concluded the excess was due to gas seeping up from the Fayetteville formation, which covers a large part of Arkansas.
Southwestern’s system of learning by changing one variable per well in search of better ways has been typical of the industry’s approach to steady improvement. The thinking by Olson and other experts is that shale formations have a lot of upside that can be unlocked with a greater understanding.
Software-Based Deepwater-Blowout- Preventer Testing
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 21688, ’Advances and Effects of Software-Based Deepwater-Blowout-Preventer Testing,’ by C. Mark Franklin, SPE, IPT Global; Tim Sargent, SPE, Noble Energy; Charles Brown, SPE, Hamilton Engineering; Gary W. Owen, SPE, Devon Energy; Steven Griffith, SPE, Shell; Jerry Osmond, SPE, Hess Corp.; Tore Gronas, Statoil; and Rick Cully, IPT Global, prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.
To advance the technology of blowout-preventer (BOP) leak detection through a software-development initiative, operators, service providers, and drilling contractors established an industry consortium in early 2009. The initial development focused on testing BOPs in deep water. Upon completion of the pilot program on five deepwater rigs, the results exceeded original expectations. The test results proved the software effective, efficient, and rig friendly.
Introduction
As drilling moves into deeper water and use of nonwater-based fluids increases, the challenges associated with obtaining effective pressure tests continue to grow. Prevailing interpretations of regulatory requirements to “hold pressure” have been to demonstrate a “flat line” on a pressure chart for a specified period of time. With the relatively low resolution of a circular-chart recorder (CCR), a flat line was produced, essentially, when the resolution of the device was not exceeded (typically 4–6 psi). Also, excessive damping and manipulation would not be recorded.
Joint-Industry Project (JIP)
During 2009 and 2010, four operators, with the support of several service providers and drilling contractors, participated in a JIP. As the main goal, the consortium wanted to develop state-of-the-art leak detection, with best practices for testing BOPs in deep water. The JIP was set up in two phases.
Phase-1 gathered digital data from BOP tests performed in the Gulf of Mexico (GOM) and around the world. Archived data were used as test data, and a library of more than 100 data sets was built. Review of the test results showed that each data set had from 10 to 25 tests, 86% of which represented passing tests.
The data archives provided insight into an automated approach for validating deepwater-BOP pressure tests. A software prototype was developed, along with workflow-automation features, and it was refined through multiple design-review meetings with the JIP members and the US Bureau of Ocean Energy Management, Regulation, and Enforcement.
Phase-2 field-trial installations commenced on five deepwater rigs in the GOM. The software was also run in the background in a real-time operation center during BOP and manifold testing from multiple rig types (i.e., deepwater, tension-leg-platform, and jackup). The goal of Phase-2 was to validate the software and repair software issues.