bluuebunny/crossref_metadata_2025 huggingface dataset:
Emerging Frontiers: Focus on Myanmar
Authors: Spath Jeff
Published: February 2015

President's column

In this third column on emerging geographic frontiers, I want to focus on what may be the fastest developing country in the Eastern Hemisphere—politically, demographically, and certainly from the standpoint of upstream oil and gas. Myanmar, often referred to as Burma, has been largely isolated from the global economy for roughly 50 years due to oppressive military rule and extensive human rights violations. In 2012, under newly appointed president Thein Sein, Myanmar began to reform its foreign direct investment laws about the same time the US and the European Union began suspending sanctions. E&P industry players, large and small, have been watching and waiting for just such reformations and are now being attracted by the potential for huge growth in the existing gas production and the potential of the country’s 17 sedimentary basins, largely offshore and unexplored.

Production History

Myanmar is one of the world’s oldest producers of oil; it exported its first barrel of crude in 1853. Two oilfields discovered in 1887 and 1902 are still in production. Today, the country is a net importer of crude oil as 90% of production is gas, most of which is exported to Thailand. With a current production of 21,000 B/D, primarily from only two fields, the need and attraction of foreign investment is clear.

The sedimentary basins are extremely underexplored and much of the available geological data were acquired with outdated technology. Estimates of reserves therefore vary widely. In 2012, the Ministry of Energy estimated offshore Myanmar crude oil reserves at roughly 540 million bbl and natural gas reserves at 65 to 72 Tcf.

Myanmar Oil and Gas Enterprise (MOGE) was created in 1963, shortly after nationalization of the oil and gas industry, in an effort to consolidate the oversight and management of the various local and global efforts to increase reserves and production. However, foreign operators were not allowed to participate in the efforts until 1988, when generic foreign investment legislation was passed. The Ministry of Energy held its first formal licensing round for onshore blocks in 2011, but due to the existing sanctions, western companies were largely absent. More recently, 30 offshore blocks were offered for licensing in June 2013, including shallow- and deepwater blocks.

Participation was prolific, including most major international oil companies. In fact, according to an energy ministry source, foreign companies’ tenders will be given priority, as they have the technology and expertise required to bring the complex and costly deepwater resources to market. Significantly, the government waived the initial requirement that foreign companies partner with a Myanmar-owned firm for the deepwater blocks, which increased the participation greatly. Results of the bidding are expected in early 2014 but one thing is clear – interest in finding and developing deepwater resources is widespread and intense.
Developing Long-Distance Power-Distribution Systems
Authors: Jacobs Trent
Published: February 2015

The vision of installing large subsea production facilities in remote offshore locations is today, simply not feasible. The problem is that subsea power systems are not designed to transmit high-voltage electricity to a production facility or pipeline tieback that may be under thousands of feet of water and 100 miles away from the nearest power plant.

Today’s subsea power-distribution technology is largely based on alternating- current (AC) technology, which, because of its electrical characteristics, can only be efficiently transmitted across a distance of 90 miles. In most cases, however, the effective distance is much less. On average, subsea tiebacks receive power from a platform or vessel located not more than 10 miles away and, in the case of most subsea processing systems, even closer. In an AC-supplied system, the flow of electricity alternates back and forth across the transmission line and is the form of electricity most commonly used in homes and businesses around the world. When long distances are involved, AC power distribution becomes a complicated operation and requires a great amount of attention to detail because of the physics involved with voltage regulation.

The search for an alternative to conventional AC systems has revealed the need for multiple technological advancements, from pressure compensated electrical switches to highly-conductive cables able to deliver power more efficiently. About 5 years ago, “We were looking at going to farther distances with alternating current instead of direct current (DC) because most of the equipment we have right now is AC powered,” said James Pappas, vice president of the Research Partnership to Secure Energy for America’s (RPSEA) ultradeepwater program.

He said that, after studying the issue, however, it was determined that using AC power could result in a 35% power loss in a 100-mile-long cable because of resistivity and other factors. Not long after that conclusion was reached, General Electric (GE) approached RPSEA with a concept to transfer all the power to a deepwater field with DC and then use a subsea transformer module located within the field to convert some of the power to AC. With this system, the expected power loss over 100 miles could be as low as 25%. “So, if you have AC components, it can convert power to AC for those components, and if you need DC, then it has DC components,” Pappas said. “It all sounds pretty simple until you want to put it in a package and then set it down in 10,000 ft of salt water.”
Technology Focus: Nanotechnology (February 2014)
Authors: Fleming Niall
Published: February 2015

Technology Focus

Nanotechnology has enormous potential in the oil industry, with numerous applications currently under investigation. These include, for example, improvements in material design for enhanced resistance to corrosion or erosion, improved and enhanced oil recovery, improved understanding of reservoirs through use of nanosensors, nanocoatings that prevent the adherence of deposits, and use of nanotechnology in drilling and completion fluids along with production chemicals.

The key word with regard to nanotechnology applications in the oil industry is “potential.” Realizing that potential is another matter. A survey of SPE papers published in 2013 describing nanotechnology applications that have been implemented in the field showed only two. There are, of course, numerous explanations for the apparent lack of papers describing field experiences, with the most obvious being that we are in an early-phase technology development and it will take time for new products to emerge in the marketplace. Our industry can be cautious when it comes to new technology, and this resistance to change could be another factor here.

A further influence is the potentially unknown consequences of introducing nanotechnology into the environment. For example, much research is focused on the environmental effect of releasing nanoparticles and the potential health risk through inhalation along with the potentially damaging consequences of these particles entering the food chain. It will take time to work through these issues before nanotechnology can be described as mainstream.

Where does the future lie for nanotechnology in the oil industry? It is too early to say, with too many unanswered questions remaining. Nevertheless, given the effect that nanotechnology has had in other disciplines (for example, medicine), it would be surprising if nanotechnology had little effect on the oil industry.

The papers selected this year include two examples presenting field implementation of nanotechnology. Let’s hope that, in the future, many more papers of this type will appear in the SPE literature. JPT

Recommended additional reading at OnePetro: www.onepetro.org.

OMC 2013-105 Nanotechnology Applications in Drilling Fluids by Katherine Price Hoelscher, M-I Swaco, et al.

SPE 164461 Illuminating the Reservoir: Magnetic Nanomappers by Abdullah A. Al-Shehri, Saudi Aramco, et al.

SPE 166140 Crosswell Magnetic Sensing of Superparamagnetic Nanoparticles for Subsurface Applications by Amir Reza Rahmani, The University of Texas at Austin, et al.
The Intersection of Bytes and Barrels
Authors: Hite J. Roger
Published: February 2015

Guest editorial - No abstract available.
Hydraulic Fracturing: Fracture Half-Length From Design, Buildup, and Production Analyses
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 84491, "Closing the Gap: Fracture Half-Length From Design, Buildup, and Production Analysis," by R.D. Barree, SPE, Barree & Assocs., and S.A. Cox, SPE, J.V. Gilbert, SPE, and M. Dobson, SPE, Marathon Oil Co., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Slick-Water and Hybrid Fracturing Treatments: Lessons Learned
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89876, "Slick-Water and Hybrid Fracture Treatments in the Bossier: Some Lessons Learned," by Mukul M. Sharma, SPE and Phani B. Gadde, U. of Texas at Austin; Richard Sullivan, SPE, Richard Sigal, SPE, Robin Fielder, SPE, and David Copeland, SPE, Anadarko Petroleum Corp.; and Larry Griffin, SPE, and Leen Weijers, SPE, Pinnacle Technologies, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

To better understand the process of fracturing tight gas sands, a comprehensive data set was gathered and analyzed for the Bossier formation in the Dowdy Ranch field. The bottomhole treating pressures were higher than expected on the basis of the measured stress profiles. Effective fracture lengths derived from pressure-buildup analysis and history matching of production data were significantly shorter than designed fracture lengths (or those predicted from uncalibrated fracture models). The data collected and analyzed provided valuable insight into the performance of water and hybrid fracturing treatments in tight gas formations.

Introduction

Waterfracs and hybrid fracs are the stimulation treatments used in many low-permeability reservoirs. Typically, improving the performance of gas wells in marginal gas plays requires improvement of fracturing technologies. To ensure that these gas wells remain economically attractive, even at modest gas prices, completion and fracturing practices must be optimized.

Research was aimed at improving the performance and reducing the cost of fracture treatments by acquiring and analyzing fracture-treatment data from the Bossier play in east Texas. Six gas wells (data wells) were identified in the Dowdy Ranch field for a detailed analysis of the well and fracture-treatment data before, during, and after a fracture treatment. The full-length paper details data acquired in Anadarko Petroleum Co.’s Anderson No. 2 well, summarizes findings, and presents recommendations for better fracture treatments on the basis of lessons learned.
Beyond Beta Factors: A Model for Darcy, Forchheimer, and Trans- Forchheimer Flow in Porous Media
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89325, "Beyond Beta Factors: A Complete Model for Darcy, Forchheimer, and Trans-Forchheimer Flow in Porous Media," by R.D. Barree, SPE, Barree & Assocs., and M.W. Conway, SPE, Stim-Lab Inc., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

Darcy’s law is valid in a relatively small velocity region. Forchheimer’s equation, with its inertial-flow parameter, β, is used as an extension of Darcy’s law beyond the linear-flow region. This “trans-Darcy” flow is important in hydraulic-fracture-conductivity calculations, in which flow velocities in the proppant pack are much higher than in the surrounding reservoir. The computation and presentation of β values as functions of closure stress and permeability are important for proppant selection and fracture-treatment design. A single equation was developed that describes the relationship between rate and potential gradient for porous-media flow over the entire range of values of Reynolds number, NRe.

Darcy's Law

From Darcy’s observations of experiments on flow rate, he concluded that flow rate varied in proportion to the imposed head and inversely to the height of the sand pack. The flow rate could be related to the imposed head through a linear proportionality involving a constant, k, which is a coefficient dependent on the permeability of the sand layer. The concept of a constant “Darcy” permeability, suggesting a linear relationship between flow rate and potential gradient, was accepted until empirical observations of flow rate at higher differential pressures confirmed that the relationship between flow rate and potential gradient becomes nonlinear at sufficiently high velocity.
Overview: Production Operations (March 2005)
Authors: Rogers John D.
Published: February 2015

There has been much debate about when individual countries and the world will peak in oil and gas production. It has been reported that brownfields accounted for less than 20% of the world’s oil production in 1982, but nearly 45% in 2002. A simple linear extrapolation suggests that by 2012, one-half of the world’s oil production will come from fields where production rates are declining. Generally, as a field matures and proceeds on its downward economic spiral, water-related problems escalate. This year, more than 40% of the nearly 100 papers reviewed for this feature were related to scaling and treatment. Many of these papers were from the Middle East, North Sea, and South American provinces. Implementation of innovative methods is needed to arrest declines and increase recovery factors.

Production optimization has two main objectives. One is to increase maximum production while minimizing capital expenses. The second is to reduce the inevitable production decline of a field. One interesting case is that of the Sacroc field in west Texas. This field has produced under an enhanced-oil-recovery project for more than 30 years with a high decline rate. After infrastructure rejuvenation, new data-acquisition processes, innovative interpretation, and sound engineering management, considerable cost savings were accomplished in recent years, significantly curtailing the decline.

One of the primary factors limiting production performance has been the lack of timely and reliable data analysis. A recent paper (SPE 87121) suggested that timely, reliable tools and training in the analysis of drilling data could be of great benefit to cost-effective drilling. The management of reliable real-time data from all segments of the oil and gas exploration and production process becomes a workflow-management challenge to make effective, relevant, and timely decisions.

The uptake of credible emerging hardware advances technology and enhances the overall industry experience and learning curve. The Natl. Petroleum Council’s 2003 report suggested that higher prices and difficult resources should catalyze increased efforts in research, development, and application of technologies. This will be critical if the recovery factor of the inevitable brownfields is to be economically improved.

Additional Production Operations Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 90430 - Successful Implementation of Resurgent Relative-Permeability-Modifier Technology in Well Treatments Requires Realistic Expectations

SPE 88543 - Impact of Dynamic Simulation on Establishing Watercut Limits for Well Kickoff

SPE 89837 - Cleanup of Water Blocks in Depleted Low-Permeability Reservoirs

SPE 91041 - Web-Based Hosting of Multiassets and Multiusers: Production Workflows

SPE 90792 - Integrated Process Improves Production of the Almond Formation in the Wamsutter Field, Wyoming: A Low-Permeability Case Study of 5 Years of Continuous Improvement in Well Performance
The Effect of Thief-Zone Identification and Shutoff on Water Production in the Nimr Field
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 91665, "Impact of Thief-Zone Identification and Shutoff on Water Production in the Nimr Field," by Richard S. Medeiros, SPE, Petroleum Development Oman; Deepankar Biswas, SPE, DeGolyer and MacNaughton; and P.V. Suryanarayana, SPE, Blade Energy Partners, prepared for the 2004 SPE/IADC Underbalanced Technology Conference and Exhibition, Houston, 11-12 October.

The full-length paper describes ongoing efforts to improve the performance of Nimr wells by identifying and shutting off thief zones and summarizes the results to date. Underbalanced drilling (UBD) data have shown that rogue fractures and bypass zones play a key role in the movement of water through Nimr reservoirs. UBD was used to identify nonmatrix water-bearing features and shut them off by use of different shutoff techniques, including a new selective shutoff completion tool.

Introduction

The Nimr field in southern Oman is a group of six fields, most of which are mature oil fields operated by Petroleum Development Oman (PDO). The fields A, B, E1, E2, and G produce medium-gravity viscous oil under strong bot-tom waterdrive. These fields contain more than two billion bbl STO initially in place and have been on production since the mid-1980s. Initial development was by vertical wells, but since the mid-1990s development primarily has been by horizontal wells. Production is from a combination of Cambrian aeolian and carboniferous glacial sediments. Reservoir het-erogeneity is high, particularly in the glacial Al Khlata reservoirs. Combined production from the Nimr fields accounts for more than 10% of current PDO oil production and is produced from approximately 500 active wells at an average 93% water cut. A combination of unstable displacement, strong aquifer drive, complex geological settings, and nonmatrix permeability events has resulted in unpredictable new-well performance with progressively higher initial water cuts. In this respect, Nimr presents the typical problems of a mature field—that of water movement and its effect on sweep and recovery. One of the key developmental strategies has to be identification and mitigation of water movement, thus reducing the amount of water produced and improving net oil production.

UBD. UBD began in the Nimr A field in 2002. UBD typically is used to increase well productivity by eliminating drilling-induced formation damage for faster drilling/penetration rates. Although UBD was initially used in Nimr for these objectives, its long-term value has been its reservoir-characterization (RC) data. Nimr is one of the unique fields where the RC benefits of UBD have driven its continued use in the field. The investigations carried out using UBD RC data in 2002 and 2003 have resulted in the evaluation and exploitation of two significant opportunities in addition to other large, longer-term opportunities currently being developed.
Transient Behavior of Annular-Pressure Buildup in HP/HT Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 88735, "Transient Behavior of Annular-Pressure Buildup in HP/HT Wells," by P. Oudeman, SPE, and M. Kerem, SPE, Shell Intl. E&P, prepared for the 2004 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 10-13 October.

Pressure buildup resulting from the thermal expansion of fluid in the sealed annuli of high-pressure/high-temperature (HP/HT) wells can have serious consequences such as casing failure or tubing collapse. To determine if mitigation was required for an HP/HT development, annular pressures in an appraisal well were studied with a dedicated field test that consisted of running a pressure/temperature memory gauge in a casing/casing annulus of a well and testing the well several times during a 3-month period.

Introduction

Pressure buildup in tubing/casing or casing/casing annuli is usually undesirable. Although casing design should consider high pressures at the casinghead that could result from leakage or thermal expansion of annular fluids, high pressure differences always present the risk of casing burst or collapse at weak points. Most operating companies have some form of annular-pressure management for onshore and platform wells that calls for bleeding off pressure through the wellhead once a predetermined pressure is reached.

Such schemes cannot be used in subsea wells because these wells usually will not be equipped with the option to bleed off the annular pressure and to divert the released liquids. In HP/HT wells, the high temperature in the well during prolonged production periods aggravates pressure buildup in the annuli because the thermal expansion of liquids tends to increase at higher temperatures. Because casing-string design must consider those pressures, accurate prediction of annular-pressure buildup is important.

Theoretical models to predict thermal annular-pressure buildup have been proposed by a number of authors. Usually, these models take into account fluid thermal expansion, ballooning and compression of the casings, annular fluid leakoff, and formation fluid influx.

In a first attempt to validate the theoretical models, a field test was set up to study pressure development in the casing/casing annulus of an offshore platform well. However, in this particular well, the inner (production) casing was not cemented into the shoe of the outer casing. The test demonstrated that in this case, annular-fluid leakoff completely dominated the pressure buildup. The test did not allow any conclusion to be drawn about the overall validity of the theoretical models for pressure buildup. Hence, a second test in the sealed annulus of an offshore HP/HT gas well was planned and executed.
Management: Uncertainty and Volatility in Today's Energy System: Stability, Security, and Sustainability Through Mutual Interdependence
Authors: Bozon Ivo
Published: February 2015

Many have argued that the oil and gas industry has entered a final era of very scarce resources—a new equilibrium of bottlenecked supply, steep cost curves, continued demand growth, and, as a result, continued very high price levels (Fig. 1). It is hard to believe, however, that resources are the constraint, given the enormous potential still available, including currently known and booked reserves, the increased scope for recovery of existing fields with new technologies, further potential discoveries, and the new frontier of vast oil sands and oil shales reserves that are in the money at cur-rent oil prices. In essence, according to the majority of the industry's research, we have enough resources left to sustain current production levels for between 40 and 60 more years.

Indeed, the core challenge is not one of resources but one of putting reserves into production and delivering energy to markets. This is evident already today. The expected near-term growth in production is barely enough to meet rising demand, let alone restore the spare production capacity to historic levels of 3–5 million BOPD, which helped maintain stable price levels in the past decades.

Thanks to this tight market, the outlook for demand and supply is as uncertain and volatile as it was in 1998, when oil was U.S. $10 a barrel, the industry's other big period of upheaval in the last quarter century. Moreover, this level of uncertainty is likely to continue in the coming decade. In particular, there are two specific time periods in which the current balance of supply and demand could shift dramatically: in the short term (over the next 3 years) and in the long term (after 2015).

Short-Term Demand

In contrast to the 1970s, when power generation was still a significant component of demand, today transportation fuels dominate. So far, high prices have not reduced consumers' thirst for transportation fuels, and total demand has remained more robust than in the earlier periods of price increases.

However, the evidence is growing every week that demand will begin to fall in the near term. Recent increases in government-regulated fuel prices sparked large drops in demand for oil products in Indonesia (30%) and Thailand (20%). China and other countries with regulated fuel prices are considering similar moves. In the Organisation for Economic Co-operation and Development (OECD) countries, the evidence is less clear cut. Nevertheless, the transport sectors in the U.S. and Europe exhibit early signs of a slowdown in demand growth (e.g., the slowdown in U.S. sport-utility vehicle sales, the shift to lower-priced petrol grades in Germany, and the slowdown in diesel and especially gasoline sales growth in 2005 in Europe).
Overview: Hydraulic Fracturing (March 2007)
Authors: Chipperfield Simon
Published: February 2015

Hydraulic fracturing is at a crossroads.

Industry is more interested in this technology than ever before, as evidenced by the explosion of SPE hydraulic-fracturing papers over the last 30 years (from 38 in 1975 to more than 500 in 2005). But who is doing the R&D? Ideally, service companies, operators, consultants, universities, and government bodies would do this equally. The priorities of any one group would never dominate, and a healthy division would exist between technology pull (from industry) and technology push (from academia).

In an effort to better understand who is driving new hydraulic-fracturing technology, a group of hydraulic-fracturing papers in SPE's eLibrary was studied by reviewing the affiliation of SPE primary authors for 1975 vs. 2005. (The search phrase "hydraulic fracturing" was used with an average of 40% of the papers reviewed in each year.) It was determined that technical leadership has changed with time, with a reduction in primary authorship by operators and universities/government bodies (from 40 to 25% and 37 to 25%, respectively) and a corresponding increase by service companies (from 20 to 39%). This trend also was observed in the broader oil industry (Lovendahl 2003) and in the scientific community on an international level (Rapoport 2006).

The reasons for this shift in technology leadership are clear. Many operator R&D programs have declined or have been deemed noncore and completely shut down. Many government bodies are receiving less federal support and are forced to rely on increasingly limited industry cooperative funding (Lovendahl 2003). The result is that most R&D is performed by service companies. This trend could result in hydraulic-fracturing innovation having a bias toward small-step improvement, rather than revolutionary technologies.

Keeping hydraulic-fracturing R&D active is a multifaceted challenge. Hydraulic fracturing is at the highest demand ever. R&D from the full range of industry groups and academia is essential for significant technical and commercial advancements to continue.

Hydraulic Fracturing additional reading available at the SPE eLibrary: www.spe.org

SPE 99428 "A New Approach to Hydraulic-Fracturing Modeling—Fully Coupled With Geomechanical and Reservoir Simulation" by L. Ji, SPE, U. of Calgary, et al.

SPE 102326 "New Results Improve Fracture-Cleanup Characterization and Damage Mitigation" by J.A. Ayoub, SPE, Schlumberger, et al.

SPE 106052 "Pinpoint Fracturing in Challenging Formations" by K.J. Beatty, SPE, Santos Ltd., et al.

SPE 103591 "Use of Extremely High Time-Resolution Production Data To Characterize Hydraulic-Fracture Properties" by J.W. Crafton, SPE, Performance Sciences Inc., et al.
Effect of Non-Darcy Flow on Well Productivity of a Hydraulically Fractured Gas-Condensate Well
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 103025, "Effect of Non- Darcy Flow on Well Productivity of a Hydraulically Fractured Gas-Condensate Well," by J. Mohan, SPE, G.A. Pope, SPE, and M.M. Sharma, SPE, U. of Texas at Austin, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

Hydraulic fracturing is a common method used to improve the productivity of gas-condensate wells. Previous simulation studies have predicted much larger increases in well productivity than observed in the field. This study showed the large effects of non-Darcy flow and condensate accumulation on the productivity of a hydraulically fractured gas-condensate well.

Introduction

A significant decline in the productivity of gas-condensate wells is caused by a phenomenon called condensate blocking. Pressure gradients resulting from fluid flow in the reservoir are greatest near the well. As the pressure drops below the dewpoint pressure, liquid condenses and the condensate accumulates near the well. This buildup of condensate is referred to as a condensate bank. The condensate continues to accumulate until a steady-state two-phase flow of condensate and gas is achieved.

Modeling hydraulically fractured gas-condensate wells requires taking into account non-Darcy flow. Gas velocity inside the fracture is three to four orders of magnitude higher than that in the matrix. Use of Darcy's law to model this flow can overestimate the productivity improvement. Therefore, it is necessary to use Forchheimer's equation to model this flow with an appropriate non-Darcy coefficient that takes into account the gas relative permeability and water saturation.

Previous simulation studies investigated the effects of well spacing and fracture length on well productivity in low-permeability gas reservoirs. It was shown that the most important parameters for determining the optimum fracture length are the formation permeability and the initial gas-in-place volume. For high-permeability reservoirs, short fractures and large well spacing provide the optimum profit, whereas for tight gas reservoirs, long hydraulic fractures and close well spacing are required to optimize profit from the reservoir.

The near-well condensate buildup reduces the productivity of a well by 50% or more. The loss in total production can be 40 to 80%. Laboratory data have shown a reduction of 91 to 97% in 2- to 5-md limestone cores and 95 to 98% in 246- to 378-md sandstone cores. The presence of water worsened the productivity loss.

Compositional-Simulation Study

A commercial equation-of-state com-positional simulator was used for this study. The reservoir is homogeneous, with a uniform porosity of 20% and a uniform permeability of 1 md. It has a net-/gross-reservoir ratio of 0.5. The reservoir dimensions are 5,000 ft wide by 5,000 ft long by 57 ft thick. The fracture permeability is 7,000 md.
Techbits: Seismic-While-Drilling Technology Takes ETW Spotlight
Authors: Moon Ted
Published: February 2015

Techbits

While Seismic-While-Drilling (SWD) methods have been investigated for nearly 30 years as a complete, real-time alternative to conventional vertical-seismic-profiling (VSP) techniques, the industry has yet to accept it beyond a rather narrow scope. Expanding this scope was the focus of a recent SPE Emerging Technology Workshop (ETW) held in League City, Texas.

SWD technology, until recently primarily referred to as drill-bit (DB) seismic, began as a method to detect the natural vibration from the end of the drill bit by means of surface geophones, enabling geophysicists and drillers to use these data in real time to optimize drilling efficiency, predict pore pressures ahead of the bit, and verify reservoir models.

This technique has been eclipsed by another method, particularly for deepwater offshore drilling applications, which is based on traditional wireline methods that use a standard offshore air-gun seismic source at the surface with suitable receivers or sensors in a downhole tool. This, together with recording and processing capabilities, is part of an enhanced logging-while-drilling (LWD) tool.

Nonetheless, proponents of DB/SWD technology believe the technique has untapped potential in certain applications. The ETW was seen as the ideal forum in which to discuss this. ETWs are interactive events designed to give participants a field's-eye view of new technologies and to expedite the adoption of these technologies by publicizing their initial successes as they move from laboratory to field.

Andy Hawthorn of Schlumberger helped organize the League City event. "When I got involved, the entire focus was on theory and processing of DB seismic. But because there are still so many limitations with it, we had to include the LWD seismic [LWD/SWD], which has replaced it more successfully on an economic basis."

Open Dialogue, Collaboration Promoted

According to SWD ETW Chairperson Bob Radtke of Technology International, the workshop's open format encouraged lively discussion and debate on the future of the technology. "We had presentations describing the current state of the art, as well as detailed sections on surface source, downhole source, emerging technologies, and case histories," Radtke said. "In addition, this workshop was unique, in that we had a special keynote speaker, Nansen Saleri."

Saleri, manager of Reservoir Management, Saudi Aramco, and a 1991 SPE Distinguished Lecturer, delivered an address titled "The Technology Factor: How It's Changing Upstream Performance." His talk described how the SWD method would be useful for increasing understanding of reservoirs in the Middle East and elsewhere, and indicated that significant producers may be ready to give this technology extensive use.

Another special feature of the ETW was the presentation of two "Legends of SWD" awards to Bruce Marion and James Rector for their 1991 demonstration of the first successful use of drill-bit reverse VSP employing drill-bit-correlated data.
Hydraulic Fracturing: Internal Breakers for Viscoelastic-Surfactant Fracturing Fluids
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 106216, "Internal Breakers for Viscoelastic-Surfactant Fracturing Fluids," by James B. Crews, SPE, and Tianping Huang, SPE, Baker Oil Tools, prepared for the 2007 SPE International Symposium on Oilfield Chemistry, Houston, 28 February-2 March. The paper has not been peer reviewed.

Over the past 2 decades, viscoelastic-surfactant (VES) fluids used for gravel packing, frac packing, and conventional hydraulic fracturing have relied primarily on external or reservoir conditions to break the fluid's viscosity. Internal-breaker technology has been developed that allows breaking VES fluids into easily producible fluids without the need for contacting reservoir hydrocarbons. Very little pressure or time is required to break the fluid when an internal breaker is present.

Introduction

During the 1980s, a VES fluid was developed for gravel packs. Also introduced was the concept that no internal breaker was required. This concept was also applied to VES fluids developed for frac packing and conventional hydraulic fracturing during the 1990s. The stated reason for not requiring an internal breaker was that the VES micelles, which impart fluid viscosity, are sensitive to and will break upon contacting reservoir hydrocarbons, including gas hydrocarbons such as methane, ethane, and propane. During production, reservoir hydrocarbons are said to come into contact with the VES fluid in the pores of the reservoir and, thereby, will readily break the VES-fluid viscosity and allow the once-viscous fluid to be removed easily. It should be noted that a viable internal-type breaker technology has not existed for VES fluids until recently. With the introduction of internal VES-breaker technology has come the ability to evaluate the need for such technology. The full-length paper details laboratory data for evaluating the cleanup of VES fluids with and without internal breaker. The data show internal breakers may improve VES-fluid cleanup without the need for relying on an external breaking mechanism and show how VES fluids without internal breaker may be difficult to move and clean up under certain conditions.

Internal Breakers

In a broad sense, internal breakers are compounds placed within the VES fluid during surface mixing that will go wherever the fluid goes, ensure the VES fluid breaks, and break the VES fluid into an easily producible fluid. The use of internal breakers also should improve the rate and ease of VES-fluid cleanup and prevent viscous emulsions from forming when problematic reservoir hydrocarbons contact, mix with, and break VES-laden fluid in the reservoir.
Permeability Updating of the Simulation Model by Use of 4D-Seismic Data
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125632, ’Permeability Updating of the Simulation Model Using 4D-Seismic Data,’ by R. Villegas, University of Leeds, and C. MacBeth and M. Paydayesh, Heriot-Watt University, prepared for the 2009 SPE/EAGE Reservoir Characterization and Simulation Conference, Abu Dhabi, UAE, 19-21 October.

A method is presented for updating a reservoir-simulation model by incorporating permeability that is derived directly from time-lapse-seismic data. The proposed method builds new permeability distributions by integrating a previous 3D-simulation model with 2D-permeability maps from the time-lapse-seismic results. These updates provide an alternative to use of a conventional gradient-based history-matching tool by itself. The largely uncertain petroelastic model can be avoided when history matching to the time-lapse-seismic data.  

Introduction

New high-resolution 4D-seismic-acquis-ition techniques have led to many advances, especially in static-reservoir-property estimation. A common reservoir-engineering-context question is to what extent can time-lapse seismic be used to refine the flow-simulation model. Although time-lapse seismic is used to solve challenges such as pressure-/saturation-change separation, researchers have been less successful in estimating reservoir properties such as permeability. Permeability is a reservoir property that has a first-order effect on simulation-model predictions and is important for optimizing the simulation-model predictions. Recent research has focused on developing a history-matching process or seismic-history-matching process to estimate permeability iteratively by use of an objective function matched exactly to the seismic data. There has been little investigation of direct transform of time-lapse-seismic attributes into average-permeability maps of the reservoir. Direct estimation of reservoir properties from 4D seismic, by transformation procedures similar to those used to estimate properties such as porosity and net-to-gross ratio, could be a viable approach. However, a major drawback of all approaches is that permeability is defined as a 2D map rather than a 3D volume. Current work addresses this challenge by designing a scheme to effectively integrate the depth-averaged mapped estimates from seismic to update the 3D-permeability field in the simulation model.
Gaining Competitive Advantage - Aligning Enterprise Architecture with Business Value
Authors: Habib Zahid , Zaheer Ashar , Ashish Ashutosh
Published: February 2015

Management

Senior management in the energy industry face a number of complex issues that can make for difficult days and restless nights. From volatile commodity prices and skyrocketing E&P costs to increased nationalism, more regulatory compliance and global recessions, there is no shortage of challenges in the energy industry.

During poor market environments, some companies adopt an extremely conservative outlook that includes sharp reductions in capital outlays, across-the-board budget cuts, and significant cost reductions. While these moves may be necessary to weather short-term conditions, they have limited long-term value and, in fact, can hamper effectiveness down the road. Energy executives seeking a more flexible, competitive organization should start at the company’s foundation—enterprise-wide processes and the supporting systems. Robust processes and proper alignment of the systems support governance, reduce complexity, eliminate redundancy, and generate sustainable cost reductions—while providing employees with the proper tools and data.

These business-facing processes and systems are built on and supported by the enterprise architecture. While companies typically focus on enterprise architecture from a back-office perspective, enterprise architecture should be viewed as enterprise-wide, all encompassing, front- and back-office foundational element. Oil and gas companies should take a hard look at their investments starting with a thorough assessment of their enterprise process, systems, and architecture.

Improve Alignment, Utilization

The accounting software used in the Houston office works. The accounting software used in the Brazil office works. But do the two programs work together? And if they do not, how much time and money does your company spend reconciling accounts?

These are the types of problems that are endemic in the energy business: legacy software programs that do not “talk” to one another, cobbled-together information technology (IT) systems from multiple acquisitions, and even separate IT groups, one supporting E&P and the other for the rest of the organization.

It is not uncommon for a field office to report that certain targets are being met—such as operational expenses, variances within range, production totals, etc.—only to find that headquarters has different sets of data and hence different results. These types of disconnects are costly both in terms of actual dollars and also in terms of productivity, efficiency, and employee satisfaction and requires significant manual consolidation, checking, and rechecking.
Spectrum: Myths and Realities About Hydraulic Fracturing
Authors: Thakur Ganesh
Published: February 2015

President's column

These days it is hard to open a technical magazine or news-paper without reading something on the topic of hydraulic fracturing, especially in the US.

Hydraulic fracturing—variously “fracing” or “fracking” nowadays (the controversy rages)—has been used by the industry for more than 60 years. Although the technique was seen worldwide, the first 30 years were primarily focused on North America but the last 30 years have seen a proliferation in its application to many new reservoir types as a means to maximize resource value. It is now seen in high-permeability oil fields in Alaska, the North Sea, and Russia; unconsolidated formations in the Gulf of Mexico and Santos Basin; and unconventional resources such as shale and coalbed methane developments.

Advances in horizontal drilling and hydraulic fracturing technology have transformed the natural gas supply in North America. With the advent of technology and know-how, the US is primed to become a gas exporter. According to a recent article in The Economist, the gas potential in Europe is similar, with an estimated “639 Tcf of technically recoverable shale gas compare to 862 Tcf in America.”1 But the regulations in Europe are more stern, the environments more geologically challenging, and reserves come at a higher cost of extraction.

Even with years of successful application and the huge potential for reserves, there are a lot of misconceptions about and opposition to the process. Unfortunately, until very recently, little has been done to educate the public and governments.

What role can SPE play in this issue? Simply, through education and the dissemination of transparent factual information. With our membership at more than 104,000 members in 123 countries, we are well positioned to help clear up the myths and shine light on the realities of this important issue. SPE facilitates best practice sharing through conferences, Applied Technology Workshops, Technical Information Groups, and publication of technical journals. In the spirit of enhancing collaboration, SPE takes a step further and exerts a special effort to hold conferences jointly with the other industry professional societies.

In 2011, SPE held its first SPE Technical Summit, which addressed the topic “Hydraulic Fracturing: Ensuring Ground Water Protection,” and resulted in a white paper based on the discussions.2 And as I write this column, SPE is hosting its fourth Hydraulic Fracturing Technology Conference in The Woodlands, Texas. The program committee chairperson, Dan Hill with Texas A&M University, commented on the importance of the conference: “As the enabling technology for the development of vast unconventional resources, hydraulic fracturing continues to increase in prominence in petroleum engineering, making this conference a critically important event for our industry. SPE plays a vital role in facilitating the right people, place, and atmosphere to discuss and document best practices for the industry.”
Very-High-Volume ESP-Lift Systems for Shale-Gas Fracture-Water Supply
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146489, ’Field Application of Very-High-Volume ESP-Lift Systems for Shale-Gas Fracture-Water Supply in Horn River, Canada,’ by Geoffrey C.J. Coppola, SPE, and Ryan C. Chachula, SPE, Encana Corporation, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

One challenge of the Horn River shale play in British Columbia, Canada, has been the increasing number of fracture stimulations required per horizontal wellbore. Critically important is the massive volume of water required to supply the continuous fracturing operations in the development. To eliminate reliance on surface water, it was decided to produce high volumes of sour water from a relatively unknown underpressurized saline aquifer. The challenge was designing an appropriate lift system capable of producing volumes up to 8500 m3/d per well while addressing unknown fluid inflows, fluid transmissibility and recharge, and reservoir-fluid-chemistry characteristics.

Introduction

The Horn River basin is in northeastern British Columbia, approximately 1600 km northwest of Calgary, Alberta (Fig.  1). The primary-target horizons are the Muskwa, Otter Park, and Evie formations, which are predominantly organic and silica-rich shale. Since 2005, slickwater fracture treatments have grown from 400 m3 of water with 10 t of proppant in a vertical well to 29 staged fracture treatments per horizontal well, with each treatment consisting of 5000 m3 of water with 200 t of proppant. As the volume and number of treatments have grown, so has the demand for fracture-treatment water. At 5000 m3/stage, approximately 150 000 m3 of water is required for one horizontal-well completion with 30 fractures. The Debolt formation was identified as a potential water source that could supply the required fracture-treatment water. A test well was drilled to determine reservoir properties and the compatibility of the water with the Horn River fracturing program. Subsequent testing of the Debolt water revealed 21 000 mg/L total dissolved solids, 60 ppm H2S concentration in the water phase, and approximately 5000 ppm of H2S in the vapor phase. The Debolt formation was determined to be underpressured, with a pressure gradient of 7.2 kPa/m.