bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stimulation Influence on Production in the Haynesville Shale: A Playwide Examination
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148940, ’Stimulation Influence on Production in the Haynesville Shale: A Playwide Examination of Fracture-Treatment Variables That Affect Production,’ by Neil Modeland, SPE, Dan Buller, and King Kwee Chong, SPE, Halliburton, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed.
In most developing shale plays, there is a learning curve for determining which factors affect well production positively and are economical. Evaluating the reservoir on a playwide basis can expedite the ability to determine the optimal treatment method. By use of public production data with a database of stimulation treatments for several hundred wells in the Haynesville shale, variables such as pumping rate, volumes, proppant (type and volume), fracture-stage designs, base fluid, and surfactant use can be analyzed to determine which ones produce a positive effect on well production.
Introduction
The Haynesville-shale formation of eastern Texas and northern Louisiana is no exception to this learning-curve development process. By combining a database of completion variables from 359 wells completed after 1 January 2009 with public production data, a multioperator playwide sample was obtained to study variations in completion strategy and consequent effects on production. This study investigated only wells that were completed through 1 October 2010, and the well-sample subset constitutes approximately one-fourth of the Haynesville-shale horizontal wells completed during this time interval.
Assumptions
When associating only completion techniques to the actual production, several assumptions were made that will not always hold true. Though all of the wells in the analysis are Haynesville-shale producing laterals, underlying inequalities are introduced by several differentiators. Wellbore placement, lateral length, and overall well construction differ from well to well. The flowback methodology remains a potential influence on overall production that is not constant across the Haynesville-shale play. Several operators have suggested that flowing back wells less aggressively has increased the estimated ultimate recoveries. Also, when working with monthly production data from a public-domain source, excessive shut-ins of the wells might not be distinguishable in the data set and could portray wells as being lower quality than they really are.
Therefore, certain apparent trends could be prone to masking when variations in well construction and flowback parameters are disregarded for this analysis. Production normalization was required in some instances to account for variations such as number of stages or perforation clusters to adequately single out a certain completion variable as the variable of focus.
Technology Focus: Seismic Applications (March 2012)
Authors: Kleemeyer Gerd 
Published: February 2015

Technology Focus
Following an increased investment in advanced seismic solutions, we have experienced some remarkable boundary shifts in seismic-data quality in recent years. Significant improvements have been achieved in densely sampled wide-azimuth seismic acquisition and in wave-equation-based imaging techniques, such as full-wave-form inversion and reverse time-migration, in processing. Also, emerging marine broadband-seismic solutions promise a real step change in resolution, offering unprecedented detail in subsurface interpretation and enhanced penetration of low frequencies for deep imaging.
Massive changes are also happening in the amount of data being acquired, leading to new challenges in processing and interpretation. The channel count for onshore-acquisition systems continues to increase, and new records have been set in the towing capacity of marine-seismic vessels. These continuing developments enable efficient acquisition of larger and denser surveys with longer offsets and rich azimuth data. However, these developments generally are also associated with an increased footprint that must be managed both operationally and environmentally.
It is, therefore, evident that not all new techniques can be ported easily to all environments. Adequate solutions must be chosen from the growing geophysical toolbox, balancing technical aspects with operational constraints and business requirements. Large-scale regional exploration surveys in environmentally sensitive or remote areas can differ significantly from detailed surveys required for infill-drilling targets. Flexible and scalable survey techniques are particularly important to enable smart data acquisition in areas where access had been notoriously difficult because of environmental, operational, or economic restrictions.
This seismic feature provides examples for ongoing boundary shifts in seismic technologies complemented by a guide for the interpretation of microseismic data and a pilot study about pushing time-lapse seismic monitoring toward carbonate reservoirs. A common element of the documented successes is continued commitment to and investment in technology and a close integration with business.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 146144 High-Density OBC—A Step Change in Reservoir Imaging: A BP North Sea View by Daniel Davies, BP plc, et al.
OTC 21937 Application of Geophysical Technologies and the Impact on Shell’s GOM Field Development by Jan Douma, Shell E&P, et al.
SPE 142211 Recent Advances in Pore-Pressure Prediction in Complex Geologic Environments by Alan R. Huffman, Fusion Petroleum Technologies, et al.
Interpreting Microseismic Measurements: Practical Guide
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144067, ’A Practical Guide To Interpreting Microseismic Measurements,’ by C. Cipolla, SPE, S. Maxwell, SPE, M. Mack, SPE, and R. Downie, Schlumberger, prepared for the 2011 SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 14-16 June. The paper has not been peer reviewed.
Thousands of hydraulic-fracture treatments have been monitored in the past 10 years with microseismic mapping, providing measurements that show a surprising degree of diversity in event patterns. Interpretation of the microseismic data to determine the geometry and complexity of hydraulic fractures continues to focus on visualization of event patterns and on qualitative estimates of the stimulated volume, which has led to wide variations and inconsistencies. Comparing the energy input during a hydraulic-fracture treatment with the resultant energy released by microseismic events demonstrates that the seismic deformation is a very small portion of the total deformation.
Introduction
Hydraulic-fracture microseismic monitoring (MSM) has increased our understanding of fracture propagation, especially in unconventional reservoirs. MSM, which is a straightforward application of earthquake-seismology principles, consists of the detection, location, and further analysis of extremely small seismic events induced by the fracturing process. Typically, multiple-receiver arrays are positioned over a 300- to 1,000-ft vertical interval in a single nearby offset well. The microseismic events usually are not detectable as discrete events at the surface, but only from other wellbores within approximately 3,000 ft of the fracture-treatment well.
Typically, microseisms are represented adequately by a double-couple source, which implies shear slippage that releases stress over some area. In competent rocks, shear slippages occur on pre-existing planes of weakness as a result of the changes in stress and pore pressure induced by the fracturing process. When fracture growth is relatively planar, these changes in stress and pore pressure usually result in a narrow band of microseisms that clearly defines the azimuth and geometry of the hydraulic fracture. However, complex fracture behavior is often interpreted from microseismic data, as evidenced by very intricate event patterns with width/length aspect ratios greater than 0.5. MSM data have revealed a large variation in hydraulic-fracture growth, from relatively simple planar fractures to very complex fracture networks. Understanding fracture growth and the degree and nature of hydraulic-fracture complexity is essential to selecting the appropriate stimulation design and completion strategy.
Seismic Unwired: Going Wireless in Difficult Terrain
Authors: Rassenfoss Stephen 
Published: February 2015

Seismic Unwired
The Cook Inlet has a long history of oil production, with more than 1.3 billion bbl produced and the potential for more. But ever since production peaked at 230,000 b/d in the 1970s, there has been little exploration as it dwindled to around 12,000 b/d.
Stories about the decline point out that the Cook Inlet was eclipsed by far larger finds on Alaska’s North Slope, such as Prudhoe Bay.
Still it does offer the potential for significant conventional oil finds onshore and in shallow waters offshore. A 2011 assessment by the US Geological Survey (USGS) covering the entire inlet estimated there could be up to 1.3 billion bbl of oil to discover—its mean estimate was nearly 600 mm bbl of oil plus 13.7 Tcf of natural gas from conventional formations. Plus significantly more gas from unconventional ones.
Unlike the North Slope, there is a ready market for natural gas. The nearby city of Anchorage depends on the inlet for natural gas and is concerned about dwindling local supplies, and the location offers transport links not available in the far north.
Past exploration suggested the underground structures likely to hold hydrocarbons could readily be identified using 3D seismic.
But there have been few surveys using advanced seismic technology and they generally covered small areas. That is not surprising considering the inlet’s treacherous tides, punishing winter weather, endangered Beluga whales, and the brown bears thriving in the wildlife preserves on its shores. Not to mention the permitting process.
That all changed when Apache Corp. began an aggressive leasing program a few years ago, gaining rights to explore more than 1 million acres. The big independent exploration company saw the potential for discoveries, particularly in unexplored deeper horizons, and based on its experience elsewhere it believed it could deal with the problems associated with doing a large-scale seismic survey.
Obtaining permits to shoot seismic in the inlet required creating a monitoring program, with specially trained and equipped observers making sure the operation followed regulations that can shut down seismic work if certain endangered mammals are within a 6-mile radius, and where sounds could affect animals.
Putting out the sensors needed to record those echoes presented another set of natural challenges in waters where tides can change the water level by as much as 35 ft. Currents up to 7 mph (6 knots) rule out towing streamers that move with the current, which also has presented problems for strings of seafloor receivers wired together using cables.
“There were horror stories in the past of cables drifting in the currents. Currents are a big problem,” said Mike Yates, senior staff geophysicist for Apache, which also experienced electrical problems with a cabled system, caused by the salt water.
On land, laying out long lines of receivers connected by cables was a problem because the permits banned cutting through the brush to create the relatively straight paths needed for cables, and forced detours around protected areas, such as bear dens.
Breaking Up Is Hard To Do: Creating Hydraulic-Fracture Complexity in the Bakken
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163827, ’Breaking Up Is Hard To Do: Creating Hydraulic-Fracture Complexity in the Bakken Central Basin,’ by C. Mark Pearson, SPE, Larry Griffin, SPE, and Chris Wright, Liberty Resources, and Leen Weijers, SPE, Liberty Oilfield Services, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 4-6 February. The paper has not been peer reviewed.
Drilling the Bakken in North Dakota has increased dramatically over the past several years as operators sought to hold acreage and create value with the drill bit. Much of this activity has been in the central-basin portion of the Williston basin where wells drilled before 2008 were uneconomic. Advances in completion technology caused a fundamental shift in economics, and the whole central-basin area, greater than 2,500 sq miles, has approximately 100 rigs drilling. The greatest change in completion design was incorporating high-intensity multistage fracturing. The Bakken completion design is different from other shale-gas developments, with the widespread use of uncemented liners with external packers in the openhole lateral to create the multistage zonal isolation.
Introduction
The Bakken formation (highlighted in red in Fig. 1) is part of the Williston basin, which spans southern Saskatchewan and Manitoba in Canada into North Dakota and Montana in the United States. The basin was formed as a subtle down- warping between the Superior craton to the northeast and the Wyoming craton to the southwest. The Williston basin is a gently dipping basin with very little structural deformation, except for a few structural features including the Nesson anticline and the Cedar Creek anticline, shown in Fig. 1.
The Upper and Lower Bakken shales are prolific source rocks for the petroleum system. The middle member consists of five to seven distinct lithofacies that range from silty sandstone on the east flank of the basin to silty dolomite on the west flank. Porosities in the middle member range from 4 to 10%, and permeabilities generally are less than 0.1 md.
Development History
The first Bakken-formation well came on production in 1953, 2 years after first oil production in North Dakota. Over the next 15 years, a total of 42 vertical wells were completed in the Middle Bakken or Three Forks formations. Commercial production required the existence of natural fractures associated with the uplift and could be correlated to the second- derivative curvature in the formation.
Experiments Examine Shear-Enhanced Two-Phase Flow in Athabasca Sands
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 160092, ’Shear-Enhanced Two-Phase-Flow Properties in Athabasca Sands,’ by Syed M. Farrukh Hamza, SPE, Jon E. Olson, SPE, and Jon Holder, The University of Texas at Austin, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.
Field results in steam assisted gravity drainage (SAGD) heavy-oil operations suggest formation permeability changes during production operations. This process was investigated using samples constructed from loose Athabasca sand. Results indicate that permeability changes and endpoint oil- and water-saturation variation are a function of loading boundary conditions. Overall, laboratory experiment results support increased permeability from steam injection in heavy oil; and, more importantly, the observed reduction in residual oil saturation implies that SAGD-induced deformation should improve recovery factors.
Introduction
Athabasca Oil Sands Properties. The Athabasca oil sands are relatively shallow deposits containing quartz sand, silt, clay, water, and bitumen. Most of the oil-rich sands are fine-to-medium grained with some silt- and clay-sized material. The quartz grains are water-wet. The porosity estimates range from 32 to 46%. Oil sands are loose sands, held together by bitumen. However, bitumen does not act as a cementing agent because it is a Newtonian fluid and, hence, provides no shear resistance at a zero shear rate. As a consequence, it cannot contribute to the static mechanical strength of the material, provided that the deformation does not proceed very rapidly.
SAGD. During SAGD, steam is injected into the Athabasca oil sands reservoir at high temperature and pressure. The changes in pressure and temperature cause changes in stress and deformations, which result in formation shearing and permeability changes. The deformation response of Athabasca oil sands is stress-path dependent. The thermal expansion of the reservoir from the injected steam causes thermal stresses in the horizontal direction because the reservoir is bounded laterally by the surrounding rock formations. The vertical stress from the over-burden remains constant because, at shallow depths, the Earth’s surface is a free surface.
Study Objective. The aim of this work was to study the deformation and associated multiphase-flow properties of the Athabasca oil sands using stress paths representative of the SAGD process. Experimental results document permeability and endpoint saturation change from SAGD stress paths that can lead to a better understanding of coupled geomechanical and fluid-flow processes, the implementation of which could lead to improved recovery from heavy-oil reservoirs.
Technology Focus: Seismic Applications (March 2013)
Authors: Kleemeyer Gerd 
Published: February 2015

Technology Focus
The advanced seismic technologies available today require timely planning and close integration to maximize their value. This requirement has been a red thread in all my previous feature reviews, and this is likely to continue. In this context, the feature reviews are an excellent means to increase technology awareness across disciplinary boundaries.
Broadband seismic is the watchword for the marine-seismic industry at present. Most major marine-seismic vendors have reacted quickly to this trend and introduced proprietary broadband solutions over the last 2 years. The advertised examples and case studies show remarkable improvements in vertical resolution, and broadband acquisition sooner or later will become the norm for most marine-seismic surveys. Especially the resulting extension of the low-frequency end of the signal spectrum has the potential to enhance reservoir characterization significantly, leading to a more reliable subsurface definition, and to facilitate full-waveform inversion, even in the absence of direct well control.
These are undoubtedly exciting developments, though the challenge remains to achieve similar breakthroughs in deeper, more geologically complex settings and also for onshore seismic. Broadband acquisition alone is not a panacea, and dense spatial sampling and rich azimuth acquisition for optimal subsurface illumination and imaging remain equally, if not more, important. Fortunately, broadband acquisition and wide-azimuth seismic are not mutually exclusive, and further improvements can be expected in the not-too-distant future.
Turnaround and cost reductions continue to be important and are particularly so for unconventional plays such as shale gas or tight gas (light tight oil) reservoirs, where 3D seismic is not yet as widely applied as in conventional settings. There is an increasing realization that these reservoirs are far less homogeneous than previously assumed. Seismic-based sweet spotting and well planning can add tremendous value to the staged development of unconventional reservoirs by accelerating the most productive wells and by avoiding uneconomic producers. In addition, microseismic monitoring of hydraulic fracturing or of thermal recovery techniques helps to improve the effectiveness of the required stimulation process and to manage associated integrity concerns.
I hope the selected papers for this feature provide interesting reading.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 161112 Optimized 3D Seismic Design Geometries for High-Density Surveys by Ghiath Ajlani, CGGVeritas, et al.
OTC 23700 New Opportunities From 4D Seismic and Lithology Prediction at Ringhorne Field, Norwegian North Sea by David H. Johnston, ExxonMobil, et al.
SPE 158753 Successful Application of 4D Seismic in the Stybarrow Field, Western Australia by Chris Hurren, BHP Billiton Petroleum, et al.
Comments: Global Shale Prospects
Authors: Donnelly John 
Published: February 2015

Editor's column
Several years into the “shale revolution,” progress remains confined largely to North America. It is a viable question whether the shale oil and gas business will take off outside North America at all, or just at a slower pace.
The reasons for slow growth vary from country to country but center around lack of infrastructure, ownership rights, government and public support, an active service sector that can support the activity, and whether such production makes sense economically.
The growth in shale oil over the past few years has been impressive. Unconventional oil production in the Permian Basin, Eagle Ford, and other areas has lifted output in the state of Texas to 2.7 million BOPD. North Dakota’s production, thanks to the Bakken, has doubled to almost 1 million BOPD. Total US production reached 7.5 million BOPD last year, a yearly increase of 1 million BOPD and, according to a US Department of Energy forecast, could hit 9.3 million BOPD by the end of next year, which would make the US among the top producers in the world.
With oil prices for WTI and Brent still around USD 100/bbl, economics would appear right for continued growth in unconventional E&P. And several countries have unconventional resources rivaling that of North America. Commercially recoverable reserves of tight oil could be double or more those of North America and the geology of many of those prospects is better, according to a study released last year by IHS.
Russian’s Bazhenov shale in Siberia has been called the “next Bakken” and initial estimates suggest it could be the largest shale oil deposit in the world. Shell and Gazprom have begun drilling the first of five horizontal wells there after several years of assessment. Rosneft and ExxonMobil agreed in 2012 to jointly develop the shale and will be undertaking a study to determine the commercial potential of the resources.
The Asia Pacific region holds 74 billion bbl of technically recoverable tight oil resources, according to the International Energy Agency’s World Energy Outlook 2013. The most promising prospects are in China, Australia, and Indonesia.
Most forecasts are optimistic about China’s prospects. It is estimated to hold the world’s third-largest technically recoverable tight oil resources, 32 billion bbl across the Junggar, Tarim, and Songliao basins. Growing oil demand in the country and a supportive government should encourage production. And the country is adept at using hydraulic fracturing and horizontal well drilling because of its abundance of low-permeability fields. Advanced studies and preliminary drilling by PetroChina, Sinopec Hess, and Shell have already taken place.
A state intervention model for shale oil advancement will help countries such as China develop infrastructure needed for development. Also boosting the country’s chances are the experience that several Chinese firms have gained working in unconventional projects in North America. JPT