bluuebunny/crossref_metadata_2025 huggingface dataset:
Foam-EOR Pilot: Mature Volatile-Oil Reservoir Under Miscible-Gas Injection
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 16984, ’Successful Foam-EOR Pilot in a Mature Volatile-Oil Reservoir Under Miscible-Gas Injection,’ by A. Ocampo, A. Restrepo, SPE, H. Cifuentes, SPE, J. Hester, N. Orozco, C. Gil, and E. Castro, Equion Energia, and S. Lopera and C. Gonzalez, Universidad Nacional de Colombia, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

A successful field trial in which foam was used as a gas- injection conformance enhancer was implemented in the Cusiana field in Colombia. An extensive front-end loading (FEL), including chemical-product screening, studying foam stability at reservoir conditions, coreflood experiments, reservoir modeling, and careful selection of well candidates, was executed for this pilot. The treatment was performed in a gas-injection well in the northern part of the field that had already attained a high recovery factor (RF) with high levels of gas recycling. The operation was performed by use of a surfactant-alternating-gas (SAG) method.

Introduction

The Cusiana field is in the foothills of the Eastern Mountain chain in Colombia, and initial production was in 1994. The field comprises three stacked reservoirs (Mirador, Barco, and Guadalupe) and two fluid systems (both volatile oils) with a rich-gas cap at near-critical conditions (pressures and temperatures greater than 5,000 psia and 250°F, respectively). The initial in-place volumes were 1.5 billion STB of oil and more than 3 Tcf of gas, with the Mirador formation containing approximately 60% of the total fluid. Development strategies have included natural depletion, gas recycling, water injection, and gas-injection redistribution. Gas recycling and redistribution provided the best recoveries.

The Mirador reservoir is a low- porosity quartzarenite with significant heterogeneities in permeability, both vertically and areally. The reservoir was developed with extensive gas reinjection, beginning in the early days of production with the gas-injection wells updip on the structure. This strategy proved beneficial from the very early stages of gas injection with regard to efficient first-contact miscibility and the favorable location of the injectors. The result has been RFs greater than 50% for most of the Mirador units. After approximately 10 years of gas reinjection, high levels of recycling were observed as a result of reservoir heterogeneities and a less-efficient gas-enrichment process because of the decrease in reservoir pressure below the minimum miscibility pressure. Those conditions led to unrecovered oil in areas that are difficult to access, such as the oil rim between the producers and the aquifer, poor-quality rock layers, and bypassed areas between the producers and injectors.
Implementation Challenges: DTS Injection Profiles in the Belridge Field, California
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163694, ’The Challenges of Full-Field Implementation of Fiber-Optic DTS for Monitoring Injection Profiles in Belridge Field, California,’ by Mahmood Rahman, SPE, Daniel A. Reed, and Malcolm E. Allan, SPE, Aera Energy, prepared for the 2013 SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, 5-7 March. The paper has not been peer reviewed.

The Diatomite reservoir in the Belridge field, California, has been under pressure-maintenance water injection to mitigate reservoir compaction and improve oil recovery. Accurate placement of the injection water across this 1,500-ft-thick reservoir is essential to balance voidage and reduce in-situ compaction. However, scale buildup and casing deformation have made monitoring the injection profile by use of conventional radioactive-tracer (RAT) technology a challenge because of the inability to access wellbores for logging. Field tests with fiber-optic (FO) distributed-temperature-sensing (DTS) systems confirmed that the technology had potential to replace the RAT surveys for continuous monitoring of the injection profile. However, moving from a successful pilot to full-field implementation presented many challenges, both technical and economic.

Introduction

Belridge, one of the largest oil fields in California, is approximately 150 miles north of Los Angeles (Fig. 1). There are two major producing horizons: The shallower Tulare sands produce heavy oil (13 to 15°API) by steamdrive, and the deeper Diatomite formation produces light oil (29 to 31°API). In 2012, the Tulare produced an average of 21,000 BOPD and the reservoir produced 41,000 BOPD.

The Diatomite reservoir has very high porosity (50 to 70%), high compressibility (100 to 300×10−6 psi−1), and very low matrix permeability (0.1 to 3.0 md). The upper portion of the Diatomite formation in Belridge has a gross thickness of more than 1,500 ft (Fig. 2), with 21 major depositional cycles grouped into nine conformance units.

Initially, the reservoir was produced on primary recovery by solution-gas drive. Because of the high rock compressibility, pressure-maintenance water injection was started in the late 1980s to combat reservoir compaction. The operator has been investigating methods to evaluate injector effectiveness. One solution was extensive use of openhole wireline formation tests (WFTs) that are run in replacement wells and provide a good indication of vertical-conformance effectiveness. However, WFT pressure profiles indicate only the effectiveness of past injection; they cannot show the current state of injection conformance.
E&P Notes (June 2014)
Authors: Jacobs Trent , Rassenfoss Stephen
Published: February 2015

E&P Notes

’DuPont Touts MEOR Technology’

DuPont is ramping up the commercial-scale implementation of its microbial enhanced oil recovery (MEOR) method after nearly a decade of development and testing of what it says is a low-risk way to improve production from mature fields. Using its bioanalysis technology, DuPont has isolated microbes able to promote flow conformance through the production of a biofilm that restricts flow by reducing permeability. The company has also identified and isolated microbes that have oil-releasing (or wettability-changing) qualities to reduce residual oil adhering to the rock. Based on successful results both in the lab and in the field, the company says that its MEOR solution can increase production rates by as much as 25% at a cost of USD 10 per incremental barrel. DuPont presented the details of its laboratory tests and discussed the results of field trials at the SPE Improved Oil Recovery Symposium in Tulsa in April.

’Wintershall Sees EOR Promise in New Biopolymer’

After a year of field testing, a new type of biopolymer developed by Wintershall, Germany’s largest oil and gas producer, is showing promise as an effective enhanced oil recovery (EOR) tool in one of the country’s longest producing oil fields. The company presented the first-year results of its pilot project using the biopolymer in a pair of technical papers in April at the recent SPE Improved Oil Recovery Symposium in Tulsa. The biopolymer, Schizophyllan, is named after one of the most widespread fungi found in the forests of Germany. What is novel about Wintershall’s biopolymer is that it can survive inside high-salinity reservoirs with temperatures as high as 275°F. The triple-helix configuration of the molecular structure provides durability and high viscosity. According to the company, these tolerances are unmatched by all other commercially available polymers and will enable polymer flooding in reservoirs previously considered too harsh for such a treatment.

’Two Big Equipment Makers Working on Tougher Fracture Pumping Systems’

Pumping fracturing jobs is an equipment killer. To begin with, the job requires running enormous quantities of water and sand through a pump, which is an abrasive mix that damages pumps in ways that cannot be fixed. Adding to the pressure is the trend toward clustering wells on pad sites to allow larger, non-stop, multi-well jobs that extend run time.
Seeking Ways to Make Better Diamonds by Tending to the Tiniest Details
Authors: Rassenfoss Stephen
Published: February 2015

Diamond Drill Bits

Competition among drill-bit makers can be measured by the performance of a thin layer of industrial diamond. It is both the cutting edge of the tools, as well as the technology race among competitors seeking a competitive edge. The thumb-size cylinders made of tungsten carbide topped with a thin layer of industrial diamond are mounted in pockets in the heavy metal heads of fixed cutter bits, which have become a key product line.

The ability of these fixed cutters to efficiently grind through rock has quickly made diamond drill bits the dominant bit design, representing 80% of the footage drilled worldwide last year. That represents a rapid shift in buyer preferences in a market where bits using roller cones were once as dominant. That allowed Schlumberger’s Smith Bits to grab the largest share of a dynamic market where rivals such as Baker Hughes, National Oilwell Varco (NOV), and Halliburton see opportunities to move ahead if they can find new ways to significantly increase cutter performance.

There are many factors in determining drill-bit success, but the one that gets the most attention is narrowing the performance gap between man-made and natural diamonds. Diamond bit demand growth has tracked the marked improvement in cutters. “Compared to the cutter of 10 years ago, a cutter today is 30 times more abrasion-resistant than they were. It wears 30 times slower,” said Rob Arfele, technology discipline manager for fixed cutter drill bits at Halliburton.
Energized Fractures: Shale Revolution Revisits the Energized Fracture
Authors: Jacobs Trent
Published: February 2015

Energized Fractures

In the years since George Mitchell’s engineers first used the cocktail of water, sand, and a small batch of chemicals called slickwater to crack open the Barnett Shale in north Texas, trillions of gallons of the low-viscosity mixture have been pumped into shale formations all over the United States and Canada. While the resulting shale revolution owes much of its success to the use of slickwater, it has come at a high cost in terms of dollars and increased public scrutiny.

In response, a growing chorus of suppliers, researchers, and service companies are on a mission to get operators working in North American shale plays to re-examine their almost exclusive use of slickwater and consider displacing large volumes of it with carbon dioxide (CO2) and nitrogen (N2).

Those in the industry pushing the change say the “energized” fracturing of horizontal wells is a proven technology that stands to improve the economics of completions and the productivity of horizontal oil and gas wells. They point to a growing body of evidence from both Canada and the US that shows energized fractures greatly reduce the amount of water and proppant required to stimulate shale formations, and have the potential to increase recovery rates substantially. Internationally, the technology could help speed up lagging unconventional shale development by alleviating water scarcity issues.
In Search of Better Reservoir Imaging Using Fiber Optic Receivers Downhole
Authors: Rassenfoss Stephen
Published: February 2015

Seismic Receivers

After nearly 4 decades of work, Bjorn Paulsson has created a system using fiber optic seismic receivers so sensitive that he said it will be able to create much more accurate, detailed seismic images with features too small to be seen now, detect the sounds of fracturing never heard before, and stand up to temperatures exceeding 300°C and pressures of more than 30,000 psi.

But he needs USD 12 million from companies interested in using it in their wells, which is nearly equal to the financial backing he has received from the United States Department of Energy (DOE) to get to this stage.

Paulsson and the DOE’s Research Partnership to Secure Energy for America (RPSEA) were organizing a meeting in late May seeking the support of oil companies to develop a full-scale version of the system he describes as “more than an order of magnitude better than what we can do now. This is not a small step up, it is a huge step.”

The plan is to build a system that can place 200 fiber optic seismic sensors, each of which has three channels (3C) allowing it to detect the direction of incoming signals along three axes, deep in a 30,000-ft deep well. There would be a receiver every 50 ft covered by a metal housing capable of standing up to the extreme pressures found in wells in the ultradeepwater US Gulf of Mexico, and clamped tightly onto a drilling pipe that can deliver it to the end of a long horizontal well.
Technology Focus: Coiled-Tubing Applications (June 2014)
Authors: Crabtree Alex
Published: February 2015

Technology Focus

It has been said that there is nothing new under the sun, which, if true, would imply that, in a mature industry such as ours, there is little opportunity for innovation or original thought. Another oft-quoted idiom is “to think outside the box,” which raises the questions for me of “What box?” and “Who keeps making these boxes?” Are we really in an industry that is so mature that it is devoid of new thoughts and incapable of generating new concepts to meet the challenges that we face?

I would contend not. The coiled-tubing industry has always been defined by energetic and innovative people meeting the new challenges they encounter. Today is no exception. Wells in which coiled tubing is used have become deeper, have longer horizontal sections, have higher pressures, and are less accessible because of platform and crane limitations. The recent SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition held in The Woodlands, Texas, showcased varied solutions, both in the exhibition hall and in the technical sessions. Innovative downhole tools; newer, stronger materials; new fluid additives; improved equipment; software improvements; and a deeper understanding of fundamental mechanics were among the many progressive steps being shared with attendees. Older techniques that had been rethought and applied to today’s issues were also presented.
Enhancing Offshore Coiled-Tubing Interventions in Difficult Weather Conditions
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24693, ’Enhancing the Operational Envelope for Offshore Coiled-Tubing Interventions To Be Performed in Monsoon Season,’ by Reawat Wattanasuwankorn, Franklin Hammer, and Richard Christieson, Halliburton—Boots & Coots, and Yan Song and Nick Long, Brunei Shell Petroleum Company, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed. Copyright 2014 Offshore Technology Conference. Reproduced by permission.

An operator requiring an offshore coiled-tubing (CT) intervention offshore Brunei in the South China Sea encountered challenging monsoon weather conditions as well as limited and aging offshore facilities. Innovative technologies from various applications, including a full-catenary CT system, a dynamic-positioning (DP) vessel, a knuckle-boom crane, and a heave-compensated gangway, were combined to provide the operator with a successful solution for CT-intervention improvement.

Introduction

Operations were performed in the Darussalam offshore waterflood oil field. The field’s average sea depth was approximately 30 m of water, and the field was approximately 70 km northeast of Seria. A central field complex had living quarters for approximately 160 personnel, gas lift and compression facilities, and water-injection facilities. Waterflooding was a significant factor supporting the hydrocarbon-production levels, and, to increase hydrocarbon production, water-injection improvements were required.

During monsoon season, the conventional well-intervention vessel had a limited operating envelope because it was unable to hold in a rough sea position and lacked emergency-disconnect CT and hydraulics-hose systems and a compensated gangway. These limitations made safe operation impossible during monsoon season. Once the operating rate was deemed limited, stimulation (acidizing) activity was postponed, thus affecting production results. However, with new concepts of intervention, the vessel was able to continue operating during rough sea conditions safely and more efficiently.
Technology Focus: Matrix Stimulation (June 2014)
Authors: Morgenthaler Lee
Published: February 2015

Technology Focus

Matrix stimulation encompasses pumping processes used to improve the connection between the wellbore and the reservoir. They are effective in a wide range of lithologies and have been successful in most types of completions: cased and openhole, horizontal and vertical, simple and complex, injectors and producers. Wells are matrix stimulated during completion and to remove production- or injection-induced impairment. The defining characteristic of matrix stimulation is the use of chemical systems to dissolve material in the near-wellbore region pumped at pressures below those that propagate reservoir fractures.

Chemical systems have been developed to attack carbonates (impairment and reservoir material), organic deposits, aluminosilicate minerals (fines), and sulfate scales. They have been used widely below approximately 120°C, but formulating effective systems for higher temperatures is a challenge. Carbonate dissolution is generally extremely rapid at downhole conditions. Current developments are focused on controlling this reaction either with novel organic acids or with gel systems whose rheology changes with the acid reaction. Solvents for organic deposits and sulfate scales react very slowly. The challenge is to speed up the reaction and develop treatment methods with the necessary contact time. The reaction with fines is extremely complex and can lead to precipitation of solids that are more damaging than the minerals themselves. Several promising new chemistries combining chelants and organic acids are being studied to prevent these damaging precipitates.
Placement of Stimulating Fluids in Multilayered Carbonate Reservoirs
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166184, ’Achieving Optimum Placement of Stimulating Fluids in Multilayered Carbonate Reservoirs: A Novel Approach,’ by Pierre Ramondenc, SPE, Bruno Lecerf, and Philippe M.J. Tardy, SPE, Schlumberger, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September- 2 October. The paper has not been peer reviewed.

This paper presents an alternative approach to designing and executing matrix-stimulation treatments in multilayered carbonate reservoirs. The proposed workflow does not rely on damage skin by layer during the design and the execution phases of the treatment. It instead requires a step of determining where the acid must be injected, and at which rate and volume, to meet an objective function. The workflow presented here allows decoupling the questions of optimal placement of a fluid for a given well, the performance of the materials selected, and the treatment schedule considered.

Introduction

Because acid dissolves carbonate formation without damaging reactions, the main challenge in acidizing multilayered carbonate reservoirs is to achieve optimum placement of the stimulating fluid. Heterogeneities such as the inherent dual porosity, high permeability contrasts of carbonate rocks, variable extent of damage, presence of natural fractures, or existence of differential pressure between reservoir layers—which can sometimes feature very large heights or lengths—tend to affect the fluid-injection profile. The uncertainty and often limited knowledge of those various parameters usually complicate the design of carbonate-acidizing treatments, whose outcome very much depends on how well the rock and damage characteristics have been taken into account when selecting the stimulation fluids and how and where those fluids will be pumped into the formation.
Wired-Drillpipe Technology in a Deep Ultradepleted Reservoir
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163501, ’Using Wired-Drillpipe Technology During Managed-Pressure-Drilling Operations To Maintain Direction Control, Constant Bottomhole Pressures, and Wellbore Integrity in a Deep, Ultradepleted Reservoir,’ by John Rasmus, SPE, Alain Dorel, Tony Azizi, Andre David, Ember Duran, Hector Lopez, Gare Aguinaga, Juan Carlos Beltran, and Antonio Ospino, Schlumberger, and Eduardo Ochoa, NOV IntelliServ, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March.

Wells drilled with nitrified drilling fluids require a solution for the transmission of measurement-while-drilling (MWD) surveys, bidirectional communication with rotary-steerable systems (RSSs), and transmission of MWD and and logging-while-drilling (LWD) measurements of downhole temperature and annular pressure for surface choke adjustments. Results from a well recently drilled into an underpressured reservoir in southern Mexico provided an opportunity to demonstrate the applicability of wired drillpipe (WDP) to deliver the required measurements and maintain the proper directional control while keeping the well fluids under control.

Introduction

This paper describes how WDP and managed- pressure drilling (MPD) enabled an operator to drill a severely depleted reservoir with an inverse-emulsion mud mixed with nitrogen delivered through a drillpipe-injection system.

This field has a complex structure divided by a salt intrusion into northern and southern portions. Six reverse faults oriented in different directions are involved in this structure. The reservoirs are found in the Middle and Lower Cretaceous and in the Kimmeridgian-Jurassic. Initial production was from the Lower Cretaceous interval, which is now below saturation pressure. The reservoir pressure has declined dramatically, making it necessary to provide a gasified fluid system to avoid lost-circulation problems while drilling.
Waterflooding Proves Useful in Deepwater Gulf of Mexico Overpressured Turbidites
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24111, ’Water Injection in Deepwater, Overpressured Turbidites in the Gulf of Mexico: Past, Present, and Future,’ by X. Li and K.K. Beadall, SPE, Knowledge Reservoir; S. Duan, SPE, Chevron Corporation; and J.R. Lach, SPE, Knowledge Reservoir, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.

Good primary recovery, high drilling cost, and facility limitations mean water injection is not commonly used in the deepwater Gulf of Mexico. However, waterflooding can supply additional reservoir energy for producing substantial quantities of oil trapped by limited displacement drive and poor sweep efficiency. This paper is a detailed examination of Pleistocene-to-Upper- Miocene turbidite reservoirs in the deepwater Gulf of Mexico under water injection. Waterflooding strategies have proved to be highly effective in achieving good incremental oil recovery from these reservoirs.

Introduction

So far, oil and gas production in the deepwater Gulf of Mexico is mostly from Neogene (Pleistocene, Pliocene, and Upper Miocene) reservoirs. The Neogene reservoirs can be characterized broadly as overpressured, unconsolidated, and highly compacting, with high permeability and containing black undersaturated oil of medium gravity with moderate gas/ oil ratio and some aquifer support. Although waterflooding is a mature technology, few water-injection projects have been conducted in the Neogene reservoirs because they exhibit good primary recoveries, exist in high-cost offshore environments, and are relatively small. In some of these fields, a limited volume of water was injected.
Modeling, Monitoring Aid Fight Against Scale in Alkali/Surfactant/Polymer Floods
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165285, ’The Use of Modeling and Monitoring To Control Scale in Alberta ASP Floods,’ by Kate Hunter, SPE, Lee McInnis, SPE, and Tyler Ellis-Toddington, SPE, Husky Energy, and Scot Kerr, Baker Hughes, prepared for the 2013 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 2-4 July. The paper has not been peer reviewed.

Two alkali/surfactant/polymer (ASP) floods became operational in the Taber area of Alberta, Canada, in 2006 and 2008. Throughout the course of both projects, extreme scale deposition was observed. Scale-inhibition and -remediation strategies were developed that included a comprehensive monitoring program, chemical scale inhibition, and mechanical scale-prevention techniques. From the large amount of data gathered, models were created to predict scale severity and content and to develop specific mitigation plans.

Introduction

In southern Alberta, the Mannville B Taber South (Warner) pool was discovered in 1963 and has been under waterflood since 1967 and the Glauconite K Taber (Crowsnest) pool was discovered in 1943 and has been under waterflood since 1971.

The Warner ASP flood was the first fieldwide ASP flood in Canada and began injection in May 2006. The Crowsnest ASP flood began injection in January 2008. Both floods used a 0.75-wt% concentration of NaOH as the alkali and continue to use recycled produced water for injection.

Scale and its associated problems and mitigation strategies have evolved over the course of these projects.
Leading Our Way to Zero Harm
Authors: Veazie Bob , Knode Tom
Published: February 2015

Guest editorial

A key theme of SPE’s 11th International Conference on Health, Safety, and the Environment in Oil and Gas Exploration and Production was how to achieve an incident-free workplace. Leadership is one of the critical elements of reaching this goal. This column explores components of effective leadership as it pertains to safety and its effect on employees.

Safety is about managing risk. Although the people who manage risk within an organization generally have “manager” titles, these are usually not the people who are injured. Consequently, to attain excellent safety levels, it is essential that all employees who are at risk of injuries be included in organizational risk-management activities.

Employees currently address risks in many ways, including performing audits of workplace conditions and writing work orders to ensure follow-up on key workplace conditions that require continuous improvement. Employee responsibilities also include collecting and using key information about near misses before an injury actually occurs. Perhaps most importantly, employees in many organizations are also asked to create a more interdependent workplace in which they watch out for one another and always act in service of one another in “moments of choice” to ensure that, when coworkers perform a behavior that puts themselves or others at risk, an intervention takes place before an injury occurs.  

This growing requirement of interdependent behavior within organizations requires that employees personally develop the courage to care. It also requires them to develop the humility to care enough to receive feedback, which includes dropping defensiveness and listening to peer coaches in the interest of always working more safely. This is hard work that requires personal transformation. The achievement of this degree of personal transformation requires an increased level of leadership effectiveness of those in the management positions.

So how do managers exercise increased leadership in moving toward an employee-empowerment model essential for ownership of everyone’s safety at the appropriate levels across the entity?

Empowering Employees for Safety Excellence

World-class safety, in which all employees assume the responsibility of their own safety and the safety of those around them, arises only out of discretionary behavior. Discretionary behavior is simply a choice made by each employee every day; employees cannot be mandated to comply. It is what they do all day, every day, when no one is watching.

Because discretionary behavior is the response of employees to their experience in the workplace, managers have a great deal of influence on its occurrence. Management affects employees’ workplace experience; the more positive the experience the more discretionary behavior that the employees provide. The more negative the experience, however, the more employees will just mechanically perform their work to obtain credit for success or to avoid the consequences of failure.
Pros and Cons of Applying a Proxy Model as a Substitute for Full Reservoir Simulations
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124815, ’Pros and Cons of Applying Proxy Models as a Substitute for Full Reservoir Simulations,’ by D.I. Zubarev, SPE, SPT Group, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.

A comparative study was made of proxy-modeling methods (also known as surrogate modeling or metamodeling) as a computationally inexpensive alternative to full numerical simulation in assisted history matching, production optimization, and forecasting. The study demonstrated the solution-space complexity for different simulation models and the applicability of the proxy models to mimic it. Focus was given to practical aspects of model construction and to limitations of which engineers should be aware. 

Introduction

Recent improvements in computational hardware and software have advanced reservoir modeling. However, for many workflows in uncertainty quantification and optimization with application to reservoir simulation, the availability of computing resources is still a limiting factor.

Here, a “proxy model” is a mathematically or statistically defined function that replicates the simulation-model output for selected input parameters. Typical proxy models in reservoir simulation include the following.

Sensitivity analysis of uncertainty variables

Probabilistic forecasting and risk analysis

Conditioning a simulation model to observed data (history matching)

Field-development planning and production optimization

Proxy models, combined with design-of-experiment techniques, are used widely for sensitivity analysis. Application scenarios include the traditional one-parameter-at-a-time approach for linear-sensitivity analyses and advanced experimental designs that are capable of resolving correlation and higher-order effects. For probabilistic forecasting, proxy models are used routinely as input to a Monte Carlo sampling process. The high computational efficiency of proxy models enables exhaustive sampling rates.

This study investigated the predictive quality and computational effort required for different proxy-modeling algorithms to provide acceptable results in solving reservoir-simulation problems. Three simulation models of different complexities were selected to understand the effect of the simulation-model structure on the efficiency of the proxy-model performance. Different application workflows [i.e., history matching, production optimization, hydrocarbons initially in place (HCIIP), and oil-recovery forecasting] were used to investigate the effect of the simulation-model output-data type on the proxy-model performance.
Technology Focus: Unconventional Resources (July 2010)
Authors: Polikar Marcel
Published: February 2015

Technology Focus

“Unconventionals” is a very trendy word indeed. But what is so unconventional about unconventional oil and gas resources?

Heavy-oil exploitation is widely commercialized; whether by mining of the oil sands and oil shales or by in-situ steaming or combusting processes that bring extra-heavy oil to the surface. Yet we say that such oil is unconventional. Research and pilot operations continue in an effort to increase recovery and decrease costs. When “cheap and easy oil” becomes scarce, should we then refer to these recovery techniques as “advanced,” “complex,” or “difficult” recovery rather than the exploitation of “unconventional” oil?

The same could be said for shale gas. A few years ago, such gas was said to be unconventional. However, continued research and recent exploitation with multifracs from horizontal wells have led us to think differently. Already, shale gas appears to be more conventional than coalbed methane. With the ever-increasing need for natural gas as a clean fuel, the importance of producing more gas is growing. Not all “unconventional” gas is equal: Each type is at a different stage of exploitation. While waiting to find out about the effect of renewable energies on our society, gas remains the leading fuel of choice, whether it is natural or a product of gasification of coal or biomass.

So, where do we look next? Previous centuries all favored a particular source of energy: The 19th century focused on coal because it had no other alternative, and the 20th century was mainly oil-centered. In the 21st century, we must turn wisely to the resources we have. There is no doubt that we will have to use a diversity of energy sources adapted to our needs: oil, gas, nuclear, and renewable energies will all find their share.

I expect that our energy industry will expand unconventional-resources development and at the same time advance the growth of nonrenewable sources of energy. This action will guide our strategies for future energy needs. Let us prepare for the future.

Unconventional Resources additional reading available at OnePetro: www.onepetro.org

SPE 125525 • “The Geomechanics of a Shale Play: What Makes a Shale Prospective!” by Larry K. Britt, Britt Rock Mechanics Laboratory, et al.

SPE 129085 • “A Thermal Gas-Production System From Methane-Hydrate Layers by Hot-Water Injection” by K. Sasaki, SPE, Kyushu University, et al.

SPE 125419 • “Successful Strategies for Dewatering Wells Using ESPs” by Lonnie Bassett, Borets-Weatherford

OTC 20644 • “Ocean Thermal-Energy Conversion: Strategies for System Integration and Implementation Using Commercially Available Components and Technology” by J.A. Marti, Offshore Infrastructure Associates, et al.
Montney Unconventional Gas: An Integrated Approach To Optimizing Wellbore Completions
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125970, ’Montney Unconventional Gas - Next Generation, An Integrated Approach To Optimizing Wellbore Completions Technology,’ by Rodney Schnell, SPE, Nicole Tapper, SPE, and Ryan Genyk, SPE, Talisman Energy, and Dalis Deliu, SPE, and Habib Tavakol, SPE, Halliburton, originally prepared for the 2009 SPE Eastern Regional Meeting, Charleston, West Virginia, 23-25 September. The paper has not been peer reviewed.

The full-length paper presents the evolution of well construction in the Montney play, technical and economic challenges, and the new synergy developed between drilling and completions.

Introduction

The Montney formation is a prolific tight gas reservoir in the western Canadian sedimentary basin, in both Alberta and British Columbia. In the Peace River Arch area, horizontal wells with multiple fractures are the key to achieving economic success. Using various area drilling and completion techniques as a starting point, lowering the installation cost without affecting the completion or production results was the driver for the next generation of completions. Swellable-packer systems with ball-drop-actuated sliding sleeves initially were run in various openhole configurations to allow multiple fracture treatments to be pumped in one operation, a significant savings from multiple-day operations. From these successes, a drive to reduce costs further led to cemented ball-drop sliding sleeves with a hydraulic-fracture-initiator sleeve at the toe of the horizontal well.

After installing the cemented sleeves on eight horizontal wells and improving the process continuously, it has been concluded that the system can reduce drilling and completion costs by 25% when compared to swellable-packer systems with intermediate casing and by 50% over traditional cemented liners with perforated completions. These savings are accomplished without affecting well performance negatively.

Background

Swellable Packers. To stimulate the Montney reservoir effectively with multiple fractures, it was necessary to isolate each interval. As a potential improvement to cementing a liner in place and perforating individual intervals, swellable packers were used with sliding sleeves between the packers. The sleeves were actuated using a ball-drop mechanism to isolate the portion of the wellbore that had been fracture stimulated previously. Once isolated, the next interval is accessed when hydraulic pressure from the pumping units opens the next sleeve.

The speed of the completion operations with the swellable packers and ball-drop system is very efficient. It is quite easy for the operator to achieve seven fracture stimulations in 1 day, and there were no problems encountered initiating fractures into the open hole between the swellable packers.

Production Results. Microseismic data show very good coverage of the Montney formation and show that the swellable packers were able to pro-vide adequate isolation consistently between fractures.
Lessons Learned Conducting Drilling and CO2-Injection Operations at the Victor J. Daniel Power Plant in Mississippi
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124003, ’Lessons Learned While Conducting Drilling and CO2- Injection Operations at the Victor J. Daniel Power Plant in Mississippi,’ by George Koperna, SPE, David Riestenberg, SPE, and Robin Petrusak, SPE, Ad - vanced Resources International; Richard Esposito, Southern Company Generation; and Dick Rhudy, Electrical Power Research Institute, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.

Lessons learned from a CO2-injection pilot in southeastern Mississippi highlight issues unique to injection at a power plant. Conventional oil and gas technology was used to track CO2 in the subsurface. An electric-power-generating facility hosted a CO2-sequestration demonstration as part of the Southeast Carbon Sequestration Regional Partnership. The primary goal was to provide a foundation for safe and secure storage of CO2 in a deep saline reservoir within a power plant’s property boundary.

Introduction

In 2008, Mississippi Power Company’s Victor J. Daniel Jr. electric-power-generating facility, in Jackson County, Mississippi, hosted a CO2-sequestration demonstration sponsored by the US Department of Energy (USDOE). The geological-review process identified saline reservoirs for CO2 storage, with the Lower Tuscaloosa formation as the most promising. An observation well, Mississippi Power Company 11-1 (MPC 11-1), and the injection well (MPC 11-2) were drilled during the first half of 2008. In October 2008, more than 3,000 T of CO2 were injected into the Lower Tuscaloosa formation. Fig. 1 shows the location of the two wells on the plant’s property.

Regional Characterization

The test site, like many potential deep-saline-aquifer storage sites, lies in a region with little historical oil and gas activity. As such, only sparse subsurface data were available within the area, and a regional approach to characterizing the subsurface was used. All available geological information for the region was gathered to characterize the subsurface geology.

Only one existing well penetrated the injection and confining intervals within 5 miles of the test site. No recent, high-quality seismic data were available in the immediate area. However, given that the coastal-plain strata along the Mississippi Gulf Coast are characteristically laterally extensive and contain no significant structural deformations (folding or faulting), a regional approach to describe the geology was deemed appropriate as the first step. The observation well (cased, but not completed), 175 ft from the injection well, was scheduled to be drilled and logged (with a full suite of tools) before drilling the injection well to ensure that the test site would be suitable.
CO2 Injection Into Depleted Gas Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123788, ’CO2 Injection Into Depleted Gas Reservoirs,’ by Hrvoje Galic, SPE, Steve Cawley, SPE, and Simon Bishop, SPE, BP, and Steve Todman, SPE, and Frederic Gas, Petroleum Experts Ltd., prepared for the 2009 SPE Offshore Europe Oil and Gas Conference & Exhibition, Aberdeen, 8-11 September. The paper has not been peer reviewed.

Depleted gas fields represent an opportunity for CO2 storage. However, low reservoir pressure will present a significant challenge for CO2 injection because of phase-behavior issues. This behavior will constrain injection operating parameters significantly during the early stages of CO2 injection. An efficient way of understanding and possibly resolving flow-assurance problems is to adopt an integrated-asset-modeling (IAM) approach. The IAM recognizes the interaction between all system elements and enables observing the effects of many parameter changes within the whole system. 

Introduction

The case study modeled a BP-operated asset offshore UK in the southern North Sea (UK SNS) for CO2 injection. The modeled CO2 supply would come from burning fossil fuels at a power plant. The resulting CO2 would be captured, dehydrated, compressed, and transported to an onshore pumping facility at approximately 70–80 bar and at ambient temperature (0 to 20°C).

Under these conditions, CO2 is in dense liquid phase. An onshore pump then would move the CO2 through a subsea pipeline to an offshore injection facility. From there, it would be distributed to several injection wells (most likely converted from existing production service) and injected into a depleted gas reservoir, which had initial conditions of approximately 27 bar and 90°C. The model assumed an approximately constant CO2 delivery rate of 2×106 t/a for a nominal project life of 20 years, with injection beginning in 2013.

Toolkit

The injection-modeling toolkit comprised a full-field thermal reservoir model with wells and well-network descriptions, surface-network descriptions, dynamic connections between the reservoir and the well-/surface-net-work models (acting as a data-transfer system and master controller for the integrated full-field model at each forecast timestep), and a consistent set of fluid pressure/volume/temperature (PVT) descriptions between the different models.

A major technical challenge was related to the phase behavior of CO2. As Fig. 1 shows, pure CO2 has a triple point of 5.18 bar at −56.6°C and a critical point of 73.8 bar at 31.1°C, enabling three different phase regions to be defined under real reservoir conditions: liquid, vapor, and supercritical fluid.

Keeping the CO2 in a liquid or super-critical phase is essential to realize the benefits from the high density of the fluid in terms of bulk-transportation efficiency, injectivity potential, and stored-CO2 mass.
En Route: An Unconventional Future
Authors: Labastie Alain
Published: February 2015

President's column

In the last couple of years, we have seen an extraordinary growth of unconventional gas activity that is literally reshaping our industry—notably, tight gas reservoirs and gas shales in North America and CSG/LNG projects in Australia (CSG means coal seam gas, which is another name for coalbed methane).

These advances were made feasible by technology, which made possible what was once considered impossible to achieve (production per well, sufficiently low cost per well, etc.), but also by perseverance. We must not forget that it took about 20 years to find the key to unlock the potential of these unconventional gas plays, whose resource had been identified a long while ago. This remark applies also to the development of another unconventional hydrocarbon, the oil sands of Canada; it took 20 years from the concept of steam-assisted gravity drainage (SAGD), and the first patent by Roger Butler, to significant production using this technology

As recently as 5 years ago, almost nobody was forecasting what is happening now with gas shales. Our current success has been made possible by a few technological breakthroughs, or step changes, which are by essence difficult to predict. I think that will be the case for all unconventional hydrocarbons, such as oil shales and, perhaps someday, gas hydrates. It is almost impossible to make a reliable guess about when gas hydrates will come onstream with significance, but this will happen at some time. It is also interesting to compare oil shales and gas shales—oil-shale production still faces a lot of technological barriers, and the economics look quite uncertain, which is exactly the situation gas shales were in 20 years ago.

Unconventional hydrocarbons are interesting for two reasons: (1) the resources are huge, and may cover our needs for more than a century; and (2) the geographic distribution of those resources, which is mostly in non-OPEC countries. The gas resource is important in North America, central Europe, and Australia. The oil-shales resource, as known today, is mostly in North America and “new” countries such as Jordan, Lithuania, Morocco, and a few others.

A very important point is that, in addition to “traditional” technology challenges, the development of all types of unconventional hydrocarbons is facing similar environmental issues: One is land use—in all cases, footprint is important, mostly due to the large number of wells. The other is water issues—production of dirty water (to be treated adequately), or the risk or fear of contamination of aquifers when fracturing the pay zone.