bluuebunny/crossref_metadata_2025 huggingface dataset:
Chiswick Field: Long Horizontal Wells and Innovative Fracturing Solutions in a Low-Permeability-Sandstone Gas Reservoir in the North Sea
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124067, “The Chiswick Field: Long Horizontal Wells and Innovative Fracturing Solutions in a Low-Permeability-Sandstone Gas Reservoir in the North Sea,” by G. Coghlan, SPE, and B. Holland, SPE, Venture Production, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4–7 October. The paper has not been peer reviewed.

To obtain commercial flow rates from the Chiswick field, a low-permeability gas reservoir in the UK Southern Gas basin, field development would require horizontal wells with multiple propped hydraulic fractures. Only a few such completions have been attempted in sandstone reservoirs of the North Sea. The initial field-development plan entailed two horizontal wells with 2-km-long reservoir sections, stimulated with several massive propped fractures.

Introduction

Chiswick is in a water depth of 42 m, approximately 160 km northeast of Great Yarmouth. A field-development plan was approved in 2006. The first-phase wells were completed on a minimum-facilities platform, and first gas was produced in September 2007. The field underwent a prolonged appraisal period following its discovery in 1984, directly reflecting the challenges posed by the low-quality Carboniferous sandstones that contain the majority of the gas.

Geology

The structure shown in Fig. 1 is a broad, northwest/southeast-trending, faulted anticline that is dip and fault closed with an almost square periphery. While a gas/water contact has never been drilled, a fieldwide contact at 3450 m true vertical depth subsea (TVDSS) can be inferred with fair accuracy. The area of closure is approximately 0.37 km2. The crestal part is at a depth of approximately 3250-m TVDSS. Crossfaults subdivide the field into five compartments: Alpha, Beta, Gamma, Delta, and Epsilon. Initial reservoir conditions were 3.92 MPa and 115°C at 3450 m TVDSS.

Porosity ranges from 3 to 14% and water saturation from 25 to 70%. Total gas initially in place for the Carboniferous reservoirs was estimated at 11.3×106 m2.

Chiswick Development Wells Initial development was two wells with 2- to 2.5-km-long horizontal sections, completed with five or six massive propped hydraulic fractures of 400,000 to 500,000 lbm each, spaced approximately 500 m apart. The formation dip allows a horizontal well to penetrate a succession of channels and connect several layered reservoirs. Within each channel, a propped fracture stimulates deliverability by exposing a large volume of rock to the wellbore.
Inflow-Control Devices for Reducing Water Production
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124154, ’Practical Consideration of an Inflow Control Device Application for Reducing Water Production,’ by Liang-Biao Ouyang, SPE, Chevron Energy Technology Company, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.

Inflow-control devices (ICDs) have been developed to improve well performance and enhance reservoir management by mitigating undesired water and/or gas breakthroughs that often occur as a result of a variety of factors, including reservoir-permeability heterogeneity, heel/toe effects, and different reservoir pressures in different regions penetrated by a well. Success of an ICD completion relies heavily on appropriate completion design. The full-length paper identifies several key issues that should be addressed in designing an ICD completion and discusses their effects on performance of a well equipped with ICDs.  

Introduction

Despite their superiority in production and recovery to conventional wells by maximizing reservoir contact, horizontal and multilateral completions are more prone to water and/or gas coning toward the heel of the well as a result of frictional pressure drop from toe to heel and/or breakthrough anywhere in the well because of permeability variation along the well and proximity of water traps. ICDs, a choking device installed as part of sandface completion hardware, were proposed in the early 1990s as a solution to the difficulties particularly associated with horizontal and multilateral wells. An ICD completion offers a number of potential unique benefits:

Optimize production

Delay water progress

Minimize /eliminate annular flow and thus reduce the risk of sand production behind screen and subsequent plugging or erosion “hot spots”

Mitigate the nonuniform production profile across the horizontal hole, especially in highly heterogeneous and fractured reservoirs that may result in premature water production, bypassed oil, and lower ultimate recovery

Improve well cleanup and reduce the effect of formation damage caused by drilling of the well

For sandstone, the application of ICDs should reduce the effect of heel/toe effects and high-permeability intervals, defer water/gas breakthrough, and improve well cleanup and sweep efficiency. For carbonate, the application of ICDs should help to control inflow from high-permeability intervals and limit production from each compartment based on lateral offset from gas/oil and oil/water contact to prevent premature gas and/or water breakthrough. ICDs have gained increasing popularity and increasingly are being applied to a wide range of reservoir types.
Identifying Point of Failure and Repairing Damaged Sand Screens
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 122153, ’Identifying Point of Failure and Repairing Damaged Sand Screens in Gravel Packed Wells. A Case History From the Heidrun Field,’ by Per Einar Svela, SPE, Oyvind Gustavsen, Hilde Songstad Solli, SPE, and Oystein Brandal, StatoilHydro, originally prepared for the 2009 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 27-29 May.

The full-length paper describes a method used on several wells in the Heidrun field to mitigate failures in gravel-packed screens. The method described includes how to identify sand production, the preferred way to run the well after sand production has been identified, and how to perform data acquisition to determine the point of failure. The data acquisition described includes gravel-pack logging, injection logging, and saturation logging.  

Heidrun Field

The Heidrun field is located on Haltenbanken in the Norwegian Sea. The sea depth in the area is 350 m. The field has been developed with a floating concrete tension-leg platform installed over a subsea template with 56 well slots. The northern part of the field is developed with five subsea templates. Oil and gas production started in October 1995.

The reservoir consists of sandstones in the Garn, Ile, Tilje, and Aare formations of the Early and Middle Jurassic. The reservoir is heavily faulted. The Garn and Ile formations have good reservoir quality, while the Tilje and Aare formations are more complex. Most of the formations produced in the Heidrun field have a moderate-to-low sand strength and are prone to sand production. Several approaches to sand control have been tried, and the current base-case solution is openhole gravel-packed screens. The recovery strategy for the field is pressure maintenance using water and gas injection.

Sand Management

Sand production has both a production and a health, safety, and environmental (HSE) impact. Massive sand production can result in unwanted discharge into the environment during jetting of separators because oil coats the sand being jetted out. With regard to the safety aspects, gas velocity has to be considered. A high gas velocity means high erosion risk during sand production. Wells are divided into three categories, high-, medium-, and low-erosion risk, depending on the gas rate of the well.
Siri Pilot Project: First Offshore Extraheavy and Viscous Oil
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20134, ’Siri Pilot Project - First Offshore Extra Heavy and Viscous Oil (12.3 API) Ever Produced,’ by Alexandre Dutra Sayd, Andre Luiz B. Moco, Celso C.M. Branco, Edson T. Kato, Ivan Parreiras de Carvalho Jr., Joao A. Rosseto, Jose Augusto da Silva Neto, Josiane L. Diniz, Marcelo Brennand, Marcelo Guarda, Miguel Pittella Franco, and Thomas Edison Brasil, Petrobras, originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May.

The full-length paper describes the appraisal and pilot testing of a large, offshore highly heterogeneous carbonate 12.3ºAPI reservoir in 100-m water depth. The successful pilot production started on 31 March 2008 to the floating production, storage, and offloading (FPSO) vessel Cidade de Rio das Ostras (Fig. 1). Since then, pilot production has been monitored closely by permanent-down-hole-gauge (PDG) and electrical-submersible-pump (ESP) sensors used to update a reservoir-simulation model. Preliminary results show more-viscous oil than initially expected in a more complex reservoir.

Introduction

In the early stages of exploration and production of the Campos basin offshore Brazil in the late 1970s and early 1980s, a shallow (900-m true vertical depth) Siri carbonate reservoir was discovered in water depths of 100 m. Although the volume in place was large (currently estimated at more than 300 million m3), it was considered noncommercial because of the 12.3°API oil gravity and 320-cp viscosity. At that time, there was an abundance of lighter oils to be developed beneath the same area. In addition, the technology for extracting such heavy and viscous oil in an offshore cold environment had not been developed yet. In 1993, a vertical development well, designed for the deeper reservoir, tested and collected a bottomhole oil sample. Operational problems during the well test, including water production, made it difficult to quantify reservoir parameters. In 2002, new studies were made, which led to the drilling and testing of a pilot vertical well, later sidetracked to a long-horizontal-section (2000 m) well, revealing a better-than-expected reservoir scenario. An ESP-aided flow test in the vertical well produced an impressive productivity index. In this context, the Siri reservoir appeared as a candidate for a pilot production project. Many other heavy- and extraheavy-oil discoveries were made in Campos basin, which caused additional interest in testing and development technologies.
Characterization of a Complex Carbonate Heavy-Oil Reservoir
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120423, ’Characterization of Complex Carbonate Heavy Oil Reservoir - A Case Study,’ by Afzal Iqbal,John Smith, Ali Reza Zahedi, Deemer Arthur, and Falah M. Al-Yami, Saudi Arabian Chevron; W. Scott Meddaugh, Chevron Energy Technology Company; Mansoor A. Rampurawala, SPE, Bingjian Li, SPE, and Ihsan Gok, SPE, Schlumberger Oilfield Services; and Talal Al Enazi, Kuwait Gulf Oil Company, originally prepared for the 2009 SPE Middle East Oil and Gas Show and Conference, Bahrain, 15-18 March.

The First Eocene reservoir is the shallowest producing interval of the Wafra field in the partitioned Neutral Zone between Saudi Arabia and Kuwait. Characterization of this heavy-oil reservoir is challenging because of observed variations in oil viscosity, heterogeneity related to complex mineralogy, a possible dual-porosity system, and the presence of fractures of varing scales. The full-length paper presents several aspects of an integrated approach to characterize the reservoir.

Introduction

Currently, a large-scale steamflood pilot (LSP) consisting of sixteen 2.5-acre inverted-5-spot patterns is being installed. This will be the first multipattern steamflood of a carbonate reservoir in the Middle East.

Oil was discovered in the First Eocene in 1954, and full-scale development began in 1956. The First Eocene has produced only 4% of original oil in place (OOIP), and primary recovery is not expected to exceed 10%. The oil gravity in this heavy-oil reservoir varies from 14 to 20ºAPI. The First Eocene is a depletion-drive reservoir with partial solution-gas drive and limited aquifer support. The estimated gross OOIP within the currently delineated field limit is more than 10 billion reservoir bbl.

The reservoir mainly consists of dolomitized packstones and grainstones deposited under arid-to-semiarid conditions on a shallow, very gently dipping, low- to moderate-energy inner shelf or ramp setting in a gently dipping, restricted ramp environment. The presence of minor interbedded evaporites suggests restriction was occasionally sufficient for the development of hypersaline lagoons and sabkhas. The shallowing-upward cycles are capped by mud-dominated rocks, hardgrounds, and exposure surfaces. The average porosity is 35% and the average permeability is 250 md over the gross interval. Well-log and core-plug porosity values greater than 50% are common, and measured permeability values range up to 5,000 md. The First Eocene reservoir has an average depth of approximately 1,000 ft and a gross thickness of approximately 750 ft. Three wells were used in the study to demonstrate the approach of integrating log and core data to evaluate reservoir heterogeneity.
Comments: Drilling Slowdown
Authors: Donnelly John
Published: February 2015

Editor's column

Nearly a year after the Macondo blowout in the US Gulf of Mexico, activity in one of the world’s great hydrocarbon basins is sparse and the future appears uncertain. Although the drilling moratorium was lifted by the federal government several months ago, approval of deepwater drilling permits has been slow in coming and the regulatory environment is unclear.

Drilling contractors are certainly suffering. Seahawk Drilling, one of the largest operators of shallow-water rigs in the Gulf of Mexico, announced last month that it would file for bankruptcy and sell its assets to a competitor. The company blamed the US government for regulations that had stifled drilling activity. Seahawk was “forced to seek strategic alternatives only after an unprecedented decline in the issuance of offshore drilling permits following the Macondo blowout,” Seahawk CEO Randy Stilley said in a statement announcing the bankruptcy. “The decision by regulators to arbitrarily construct unnecessary barriers to obtaining permits they had traditionally authorized has had an adverse impact not only on Seahawk, but on the sector as a whole.”

Seahawk’s assets will be acquired by Hercules Offshore in a cash and stock deal worth about USD 100 million. The deal was the second major consolidation among US rig contractors in a week, following Ensco’s acquisition of Pride International.

US Interior Secretary Kenneth Salazar in May imposed a moratorium on drilling in the Gulf and lifted it in October. Drilling in shallow water of 500 feet or less was not subject to the moratorium but the issuance of new drill permits was greatly slowed.

At a Baker Institute gathering last month in Houston, industry representatives, scientists, consultants, and government officials discussed the future of the Gulf post-Macondo. That future will depend on how US drilling policy and safety standards evolve, the panelists agreed. In 2010, the US Gulf of Mexico produced 1.7 million b/d of oil and 6 bcf/d of natural gas, just under a quarter of total US oil output and 10% of total gas production, said J. Robinson West, chairman and chief executive officer of PFC Energy, one of the speakers at the event. “If oil and gas drilling are able to continue without constraint in the Gulf, it is the young fields in ultradeep water that will make the greatest contribution to US domestic oil production and energy security,” West said. By 2020, more than half of the Gulf’s production is projected to come from ultradeep waters.

Several industry executives thought that the industry and federal regulators would soon be to a point where the issuance of deepwater drilling permits could resume. Michael Bromwich, director of the federal agency overseeing drilling activity, said he expects permits for deepwater projects to begin soon, at least before the end of the second quarter.

Meanwhile, rigs from the Gulf are leaving for other basins around the world such as Brazil and west Africa. “The deepwater industry is global and will take its capital, equipment, and jobs to other basins if it cannot operate in the US,” West said.
Technology Focus: Hydraulic Fracturing (March 2011)
Authors: Chipperfield Simon
Published: February 2015

Technology Focus

Beware the “Commoditization Trap”1!

Commoditization is the evolutionary process that reduces all products to their lowest common denominator. This process has many advantages in unconventional gas in which large resources can be developed efficiently with such “factory-style” development concepts. The commoditization-trap problem can arise when one becomes focused solely on producing a product more cheaply without consideration for the quality and new-product development.

The dangers of the Commoditization Trap can be observed when analyzing the SPE hydraulic-fracturing paper population, which, while increasing exponentially over the last 30 years, is now led by operators in less than 15% of cases (down from 37% operator driven in 1975).2 Lead-service-company contribution has, however, increased from 20 to 40% over the same period. This change high-lights the industry perception that fracturing requires little definition (a phase of increased operator involvement) and instead requires a focus on commoditization (a phase for increased service-company involvement).

Viewing fracturing as a commodity may seem reasonable considering that it has been in use for more than 60 years. However, the types of reservoirs on which this technology is used are changing rapidly and are challenging the fundamental assumptions upon which our existing candidate selection and design methodology are built.

Some operators are adapting learning processes to ensure against the Commoditization Trap.3 However, the constant shift in technical contribution from operator to service company clearly highlights that this is not an industry-wide view.

Hydraulic fracturing as a commodity is an industry misconception, and greater value can be added by those who have not fallen into the Commoditization Trap.

Hydraulic Fracturing additional reading available at OnePetro: www.onepetro.org

SPE 133456 “Thirty Years of Gas-Shale Fracturing: What Have We Learned?” by George E. King, SPE, Apache Corporation. (See JPT, November 2010, page 88.)

SPE 127888 “Modeling Fluid Invasion and Hydraulic-Fracture Propagation in Naturally Fractured Rock: A 3D Approach” by J. McLennan, SPE, University of Utah, et al.

SPE 137818 “Improved Proppant-Transport System for Slickwater Shale Fracturing” by N. Kostenuk, SPE, Trican Well Service, et al.

1http://www.imaginellc.com/avoiding-commoditization-part1, accessed 31 January 2011.

2This percentage refers to search results by company affiliation of the primary author of SPE papers.

3 The New Encana—http://www.encana.com/investors/presentations/pdfs/corporate-presentation.pdf, accessed 31 January 2011.
Evaluation of Aquifer Diversion After Large Polymer-Gel Water-Shutoff Treatments
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 132978, ’Quantitative Evaluation of Aquifer Diversion to Surrounding Wells After Multiple Large Polymer Gel Water Shutoff Treatments,’ by Ben Turner, SPE, Tiorco, and Jude Nwaozo, SPE, and Brad Funston, SPE, Marathon Oil Company, originally prepared for the 2010 SPE Production and Operations Conference and Exhibition, Tunis, Tunisia, 8-10 June. The paper has not been peer reviewed.

From April through August of 2009, seven producing wells in the Spring Creek field in the Big Horn basin of Wyoming were treated with chromium-acetate-crosslinked polyacrylamide in an attempt to reduce water production, lower fluid levels, and achieve greater drawdown, resulting in improved oil production. The wells were chosen because of their high productivity, high water cut, suboptimal operation because of pump limitations, and in some cases, marginal economics.

Introduction

The Spring Creek field is on the west flank of the Big Horn basin in Park County, Wyoming. Structurally, Spring Creek forms an asymmetrical anticline. The main oil reservoirs in Spring Creek are the Tensleep sandstone (Pennsylvanian) and the Phosphoria formation (Permian).

Both the Phosphoria and the Tensleep are connected to prolific aquifers that supply reservoir energy, but also supply a high rate of water. In most wells in the field, both formations are produced and commingled, but in many wells, the Tensleep is so productive that the well is limited in lifting capacity and the Phosporia has not been perforated. The well spacing in the field averages approximately 5 acres.

Strategy

The operator has an extensive history of shutting off water production by use of chromium-crosslinked polyacrylamide gels. By using chromium acetate as a delayed crosslinker for partially hydrolyzed polyacrylamide, a large volume (as much as 11,500 bbl in this case) can be injected and then allowed to cure for a week. When the gel cures, it reduces the permeability of the fracture and is able to withstand a high differential pressure such as that seen in the near-wellbore region of a producing well. The gel is bullheaded through tubing, with a packer set above the productive formations. Because of the large permeability difference between the fractures and the formation matrix, the gel will penetrate the fractures and significantly reduce the permeability, reducing the water production and fluid level, thus allowing the well to be pumped off and oil production to be increased. This technique has been used quite successfully in several hundred applications throughout the USA.
Alaskan Heavy Oil: First CHOPS at an Untapped Arctic Resource
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 133592, ’Alaskan Heavy Oil: First CHOPS at a Vast, Untapped Arctic Resource,’ by J.P. Young, SPE, W.L. Mathews, SPE, and E.J. Hulm, SPE, BP Exploration Alaska, originally prepared for the 2010 SPE Western Regional Meeting, Anaheim, California, 27-29 May. The paper has not been peer reviewed.

Alaska’s North Slope is a world-class petroleum resource basin with two of the largest producing fields in North America, Prudhoe Bay and Kuparuk River unit. What is not widely known is the vast resource of heavy oil above these reservoirs. Although comparable in size to these fields, it remains untapped as a result of the complexity of producing heavy oil in an arctic environment. The keys to commercializing this heavy-oil resource are primarily technology and favorable economics.  

Introduction

The total North Slope heavy-oil resource is defined by approximately 1,500 wells that penetrate the Ugnu sands for deeper targets and multiple high-quality 3D-seismic surveys. Resource size ranges from 18 to 27 billion bbl of oil in place, and the oil is found in multiple reservoir zones extending across the basin. Initial appraisal is focused on the 12 to 18 billion bbl within the Lower Ugnu (M-sand) reservoirs. 

The Ugnu structure is characterized by a normal-faulted monoclinal dip toward the northeast. The depth of the Ugnu pool varies from 4,500 ft in the east to 3,000 ft in the west.  Multiple fault families are present, as indicated by 3D seismic. The faults tend to compartmentalize the Ugnu reservoirs by providing effective updip and lateral seals.

Lower Ugnu oil quality improves to the east, corresponding to increased burial depth from west to east.  The deeper, less-viscous oil in the east is believed to be suited to simple “cold”-production techniques that exploit solution-gas drive. The shallower, heavier oil in the west is believed to be suited to energy-intensive thermal techniques that heat the oil in situ. 

Reservoir-Performance Variability

Excluding mechanical issues, most variation in well rates and recovery is likely to be associated with changes in key reservoir and fluid properties. The Lower Ugnu reservoir sands are highly unconsolidated, which limits the ability to acquire quality core samples and measure key reservoir parameters accurately. In addition, the sands were deposited as fluvial-deltaic channels, which are among the most heterogeneous reservoir types.
Don't Look to the Big Shale Plays for Innovation in Horizontal Multistage Fracturing
Authors: Themig Dan
Published: February 2015

Guest editorial

The good news is that there is plenty of innovation to talk about regarding step-change advances in horizontal multistage fracturing in many of the existing and emerging resource plays. The bad news is that you will not find these being applied in the Barnett Shale. While attending the SPE North Sea and European Area Stimulation Workshop (Berlin, Germany in September 2011) as well as the SPE Horizontal Well Completions in North America Shales Workshop (Scottsdale, Arizona in May 2011), it was evident that a number of emerging technologies are having a dramatic effect on improving ultimate recoveries in a number of plays. The interesting thing, however, is that these innovations are not being used in the so-called “legacy shale plays” (e.g., Barnett, Fayetteville) despite the fact that they are producing only break-even economics at today’s gas prices. You would expect to see aggressive innovation and experimentation in order to produce significant results in changing ultimate recoveries. The production results would suggest otherwise.

Results Speak for Themselves

At the Berlin workshop, a European producer who was investigating the Barnett to learn shale gas technology, presented a year-by-year production comparison for wells completed in the past five years. By looking at the average 24-month cumulative production from wells completed in each year, which is a pretty good gauge of ultimate recovery, it was evident that things are not improving. In fact, there was no upward trend at all in the data. Since investment continues to be significant in legacy trends, and international companies are investing billions of dollars to become players in shale gas technology, caution should be used in thinking that we have “arrived” in the Barnett.

At the SPE workshop in Scottsdale, which specifically targeted shale fracturing technology, the primary “innovation” to be used in the Barnett appeared to be moving from using one perforation cluster per stage a few years ago to three or four clusters in 2011. In essence, there was very little or no change to fracture placement and design. Based upon comments made at both workshops, there appears to be a limited under-standing of what can actually produce a step-change in recoveries.

What is a step-change? Increasing recoveries by 25%? 40%? More? The bad news is that you will likely not find process change in the Barnett or Fayetteville and, unfortunately, the industry still looks to the Barnett to understand “how shale gas is done.” So, if you are an investor who has poured billions of dollars into these plays, you may want to exercise caution in thinking that the operators in the Barnett have it figured out.

The good news, however, is that there is plenty of innovation going on in other plays that are producing step-changes in efficiencies, reducing water usage, decreasing the time required to fracture treat wells, and greatly increasing ultimate recoveries. The question is then, why are these innovations not being applied in the legacy shale plays?
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.
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