bluuebunny/crossref_metadata_2025 huggingface dataset:
Congo FDPSO An Industry First
Authors: Moon Ted
Published: February 2015

Off the coast of the Republic of Congo and at water depths of 1400 m (4,600 ft), the Azurite field began production in August from a unique facility, the industry’s first floating pro-duction, storage, and offloading vessel with drilling capacity (FDPSO). Touted as a cost-efficient solution for drilling and producing deepwater fields, the Azurite FDPSO allows vessel owner Prosafe Production and operator Murphy Oil bragging rights for developing an installation that many in the industry had seen as economically unsustainable.

The unit is equipped to process 60,000 BFPD and 40,000 BOPD and store approximately 1.3 million bbls of crude at full production, in a manner similar to a traditional floating production, storage, and offloading (FPSO) vessel. However, it is also able to drill wells without the need for other drill-ing vessels such as mobile offshore drilling units or jackup rigs. While the concept of an FDPSO has been known for decades, the launch of the Azurite marks the first time that the concept has become a reality.

Making this possible required a concerted team effort between Prosafe, Murphy, their various engineering and equipment providers, and classification provider Det Norske Veritas (DNV).

Field Development Evolves

The Azurite field, which is located in the Mer Profonde Sud block approximately 150 km off the coast, was discovered in 2005 and marks Murphy Oil’s first operated development in west Africa. Murphy was keenly aware of the need to choose a production option that would maximize recovery of the field’s estimated 70 to 75 million BOE recoverable reserves while also keeping costs to a minimum.

The initial development plan called for the subsea infrastructure to link to an FPSO, a scenario that had been successful in the region and at similar water depths. Murphy submitted a bid package in June 2006 to vessel providers for the conversion and delivery of an FPSO, at this point without any provision for a drilling component tied to it.

However, even at this stage Murphy was considering the feasibility of adding a drilling package to an FPSO—driven primarily by the expensive market for drilling rigs. “We were trying to figure out the best development scenario given our reserves position,” said Ken Hampshire, Azurite field development manager for Murphy Oil. “Other development scenarios, including spars and tension-leg platforms, required a great deal of drilling capacity that had to be brought in independently of the production facility.

“Even the FPSO option did not solve our drilling-management challenges, and at the time rig rates were extremely high,” Hampshire said, quoting daily rig rates of USD 500,000 and higher. “If you add all other costs associated with securing a rig capable of performing subsea drilling and completions in 5,000 ft of water, you’re faced with costs in the range of USD 750,000–800,000 per day.”
Systematic Study of Alkaline/Surfactant/Gas Injection for EOR
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124752, ’A Systematic Study of Alkaline/Surfactant/ Gas Injection as an EOR Technique,’ by Mayank Srivastava, SPE, Jieyuan Zhang, SPE, Quoc P. Nguyen, SPE, and Gary A. Pope, SPE, University of Texas at Austin, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.

Alkaline/surfactant/polymer (ASP) flooding is a popular enhanced-oil-recovery (EOR) method. However, foam can be an alternative to polymer for improving displacement efficiency. The use of foam as a mobility-control agent by coinjection or alternating injection of gas and chemical slugs is termed here an alkaline/surfactant/gas (ASG) process. Foam reduces the relative permeability of the injected chemical slug that forms a microemulsion at ultralow oil/water interfacial tension (IFT) and generates sufficient viscous pressure gradient to drive the foamed chemical slug. 

Introduction

In the ASP process, polymer provides mobility control during ASP slug and polymer-drive injection. However, the use of polymer has disadvantages.

High-molecular-weight polymers can plug rocks with very low permeability.

Many of the commercially available EOR polymers can be unstable at high temperature.

Some polymers can degrade mechanically from high shear stress through chokes or perforations at high flow rate.

One potential alternative to polymer is foam, which can provide mobility control in chemical-EOR processes. Liquid saturation is reduced with increased gas saturation and trapped gas in the foam, resulting in lower liquid relative permeabilities. In foam, gas bubbles are trapped in thin films of fluid called lamellae. The surface tension on the individual lamella, as well as the drag force on it as it slides along the pore walls, causes it to resist movement out of the pore throats. This resistance to movement, when combined with relative permeability reduction of the displacing fluid, results in a favorable mobility ratio and improved displacement efficiency.

In ASG flooding, as in conventional chemical flooding, the mechanism of residual-oil mobilization is IFT reduction. One of the main criteria for the success of the ASG process is the formation of stable foam with adequate mobility-reduction characteristics. The full-length paper details the results of experimental work studying the ASG process to evaluate its potential as a feasible EOR technique.
Managed-Pressure Drilling: Kick Detection and Well Control
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124664, ’Roles of Managed-Pressure-Drilling Technique in Kick Detection and Well control - The Beginning of the New Conventional Drilling Way,’ by Paco Vieira, SPE, Maurizio Arnone, SPE, and Fabian Torres, Weatherford International, and Fernando Barragan, AGR Group, originally prepared for the 2009 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Manama, Bahrain, 26-28 October. The paper has not been peer reviewed.

In times when the oil industry is looking for drilling technologies to optimize field development, managed-pressure drilling (MPD) has become an attractive technology, offering considerable benefits. MPD is an optimized drilling process used to control the annular pressure profile more precisely throughout the wellbore. The annular pressure profile is controlled from surface so that the bottomhole circulating pressure (BHCP) is balanced with the pore pressure at all times.

Introduction

Controlled-pressure-drilling (CPD) technology has enabled the commercial development of numerous oil and gas reservoirs worldwide that otherwise would not have been exploited because of technical and/or economic limitations. CPD has become possible only as a result of the integration of many developing technologies that facilitate directional control of the well trajectory, control of the BHCP, and the safe handling of drilling fluids and drill cuttings at surface.

MPD is a drilling technology that uses a pressurizable fluid system and specialized equipment to control the wellbore pressure profile more precisely. Application of this technology optimizes the drilling process by decreasing nonproductive time and mitigating drilling hazards associated with pressure fluctuations that occur when conventional drilling techniques are used.

Many drilling and wellbore-stability-related issues stem from the significant fluctuations in bottomhole pressure (BHP) that are inherent to conventional drilling practices. These fluctuations stem from the stopping and starting of circulation during drillstring connections in jointed-pipe operations; specifically, they result from a change in equivalent circulating density (ECD) that occurs when the pumps are turned on and off. MPD technology, and more specifically, constant BHP (CBHP) as a variation of MPD, is applicable to avoid changes in ECD by applying appropriate levels of surface backpressure, a technique that maintains a CBHP during the complete drilling operation. Additionally, CBHP enables safe application of conventional well-control procedures when unexpected high-pore-pressure formations are encountered. This requires that MPD systems play roles in kick detection and well control.
Kicks in Offshore UK Wells
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119942, ’Kicks in Offshore UK Wells - Where Are They Happening and Why?,’ by J.D. Dobson, SPE, Health and Safety Executive, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.

The first well on the UK continental shelf (UKCS) was spudded 44 years ago, and the area long has been considered a mature province. Despite this, kicks are still a frequent occurrence. Kicks occur in high-pressure/high-temperature (HP/HT) condensate exploration wells and in production wells in depleted subnormally pressured oil reservoirs. They occur during drilling operations and during workover operations. Analysis of data on well incidents has identified where, geographically, kicks occur most frequently.

Introduction

The Health and Safety Executive (HSE) is the regulator for oil and gas drilling on land in UK and on the UKCS. UK health and safety regulations specify which well incidents must be reported by well operators. These reportable incidents are kicks, blowouts both underground and at surface, the unanticipated presence of hydrogen sulfide (H2S), unplanned intersections and near misses, and serious failure of a safety-critical element including the primary pressure-containment envelope of the well.

The purpose of the regulation is not merely to inform HSE of the incident, but also to allow the regulator to spot trends in the industry that may not be noticeable to individual well operators and drilling contractors. The full-length paper focuses on kicks and their consequences, rather than on other incidents, but with the intention of sharing the overview more widely.

Exploration on the UKCS began in the mid-1960s, with the first major discovery in December 1965. In a mature oil and gas province such as the North Sea, it might be assumed that the frequency of kicks during drilling or workover operations would be decreasing. This study indicates otherwise.

Approach

The study is based on a review of all kicks and blowouts reported for the area in the 10 years since 1999. The intent in reviewing the data is to consider which areas of the UKCS, and which type of operation, carry the greatest risk of kicks. A second, more detailed, review was carried out for incidents in the 3-year period 2006 to 2008, which examined each reported incident in more detail, reviewing the circumstances under which the kick occurred and, where possible, identifying the underlying cause.

Areas of the UKCS

Over the last 44 years, wells have been drilled in each of a variety of discrete geographical and geological areas off the coast of the UK (Fig. 1). Although wells have been drilled in all the basins shown, the vast majority of the drilling activity on the UKCS has been limited to six discrete geological areas—southern North Sea, central North Sea, Moray Firth, northern North Sea, West of Shetland, and Irish Sea. It is in these areas that the reported incidents considered in this study have occurred.
Driving Project Efficiency and Cost Control in the Upstream Oil and Gas Industry
Authors: Bleackley David , Strathman Michael S.
Published: February 2015

Management

Today’s upstream oil and gas companies are focused on keeping pace with growing demand and driving incremental revenues by exploiting hydrocarbon reserves. This trend is particularly marked in fast-emerging, dynamic new markets such as Brazil, Russia, India, and China where operators are aggressively pursuing new market opportunities both domestically and further afield.

These opportunities include finding and developing new reserves, and equally extending the production life of existing assets. Achieving these goals presents a range of related challenges to operators.

New exploration has the inherent risk of finding new reservoirs, can be very expensive, and often takes place in challenging locations. The Macondo well blowout in the Gulf of Mexico has painfully reminded the industry of the risk and challenges. By extending the life of existing assets and production systems, the risk of the resource base is minimized and the location challenges are at least known. Oil and gas production is notoriously complex to manage and difficult to optimize due to the sometimes unpredictable nature of reservoirs. As with exploration, carefully managing expenses is always a challenge, even more so as operational costs continue to rise, while the internal expertise becomes increasingly scarce as a experienced workforce retires.

Together, these trends are stimulating demand for a potent combination of technology and talent. Operators require high-quality process engineering solutions to address complexity of operations, which are accurate, robust, easy to use, and help drive user productivity.

The best of these solutions are capable of delivering engineering efficiency throughout the design lifecycle whether they are used to help achieve minor modifications and revamps to facilities, or to deliver efficiency across the world’s largest mega-projects.

Discipline in Capital Spending and Managing the Asset Lifecycle

Getting to “first oil” as quickly as possible is important, but choosing the right assets to develop is equally critical. Fortunately, to support these business objectives operating companies can now draw on a range of process engineering, cost estimating, and integrated engineering solutions.

Engineering technology helps operators throughout the oil and gas industry control capital spending and stay on schedule when designing and building assets. In this capital-intensive business, getting oil reserves into production sooner enables organizations to achieve their return on investment objectives.
Alternative Initial Responses to Kicks Taken During Managed-Pressure Drilling
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 128424, ’Evaluation of Alternative Initial Responses to Kicks Taken During Managed-Pressure Drilling,’ by Majid Davoudi, SPE; John Rogers Smith, SPE; Bhavin M. Patel, SPE, and Jose E. Chirinos, SPE, Louisiana State University, prepared for the 2010 IADC/SPE Drilling Conference and Exhibition, New Orleans, 2-4 February. The paper has not been peer reviewed.

An industry-supported research project completed its evaluation of alternative initial responses to kicks taken during the constant-bottomhole-pressure (CBHP) method of managed-pressure-drilling (MPD) operations. This first phase was intended to provide a basis for comprehensive, reliable well-control procedures for MPD operations. Three responses were concluded to have general application: increasing casing pressure until flow out (Qout) equals flow in (Qin), shutting in the well, and adapting an MPD pump-shutdown schedule to detect and shut in low-rate kicks. Selection of the most practical response depends on well conditions and the equipment being used. Potential advantages of and constraints on the use of these responses were summarized. 

Introduction

MPD is an evolving technology used to address drilling problems encountered when using conventional, hydrostatically overbalanced drilling methods. MPD is defined by the International Association of Drilling Contractors (IADC) as a “drilling process used to control precisely the annular pressure profile throughout the wellbore.” The definition also points out that an influx of formation fluids (i.e., a kick) “will be safely contained using an appropriate process.” Establishing the basis for identifying an appropriate process or processes was the focus of this study.

CBHP Method of MPD. This method keeps the wellbore pressure relatively constant at a selected depth. This constant wellbore pressure is achieved by adjusting the surface pressure on the annulus to offset changes in the wellbore frictional pressure losses as the pump speed is varied or stopped, such as when making connections. The ability to adjust the surface pressure on the annulus is provided by a rotating control device (RCD), such as a rotating control head, by closing the annulus and directing flow through an adjustable drilling choke. Therefore, the CBHP method of MPD avoids the wellbore-pressure fluctuations that occur when starting and stopping pumps in conventional operations. Consequently, it allows drilling within a narrower “window” between fracture and pore pressures than is safe or practical with conventional methods.
The Effect of Rotating Control Devices on the Incidence of Blowouts: Onshore Texas
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 133019, ’The Impact of Rotating Control Devices on the Incidence of Blowouts: A Case Study for Onshore Texas, USA,’ by C.J. Jablonowski, SPE, and A.L. Podio, SPE, University of Texas at Austin, originally prepared for the 2010 SPE Trinidad and Tobago Energy Resources Conference, Port-of-Spain, Trinidad, 27-30 June. The paper has not been peer reviewed.

Rotating control devices (RCDs) are used to provide a closed circulating system. Conventional wisdom suggests that drilling with RCDs improves kick detection and suggests that fewer blowouts should occur when this equipment and related practices are deployed. The authors of the full-length paper find consistent statistical evidence, across a variety of regression models and variable specifications, that the use of RCDs decreases the incidence of blowouts.

Introduction

RCDs and related equipment are used to provide a closed circulating system. A closed system enables under-balanced operations (UBOs) and managed-pressure drilling (MPD). These drilling practices can facilitate drilling in otherwise undrillable formations, reduce formation damage, and reduce drilling problems such as blowouts. There is considerable literature on the technical aspects of closed systems, and industry associations and regulating authorities have promulgated guidelines for their use and for related practices.

Conventional wisdom suggests that drilling with RCDs improves kick detection and thus fewer blowouts should occur when this equipment and related practices are deployed. This outcome could be a result of active management of the pressure profile, and/or a faster response to influx where the closed system acts as a mode of initial well control before activating the blowout preventers (BOPs). Some insurers require RCDs on the basis, in part, of this perception. These views notwithstanding, there is no published analysis that demonstrates a definitive link between the use of RCDs and the incidence of blowouts. The purpose of the full-length paper is to address this gap. The authors use regression analysis to test the hypothesis that the use of RCDs decreases the likelihood of blowouts.

Data Sets

Previous studies have investigated the incidence of blowouts and have produced useful statistics and trends, and there are case studies that analyze individual blowout events in great detail. To implement the regression analyses proposed in the full-length paper, a new detailed data set is required on blowouts and on the hypothesized incidence factors. To this end, a data set was organized for onshore drilling activity in Texas during 1995–2007.
Comments: Optimism Reigns
Authors: Donnelly John
Published: February 2015

Editor's column

This year promises to be another one of healthy upstream spending. Perhaps the only thing that can derail the optimistic outlook is the global economy.

Strong oil prices will lead 2012 worldwide E&P spending to a record high of USD 598 billion, according to a new report by Barclays Capital, which annually tracks oil and gas industry upstream spending. That reflects a 10% increase over 2011 E&P spending, which also set a record, according to the survey of 350 oil and gas firms. But Barclays notes that the rate of growth will be slower than last year’s because of the global economic uncertainty that is hanging over most industries. If that uncertainty were to disappear, the E&P forecast would appear very conservative, the report said.

Spending is forecast to increase by 8% within North America and by 11% outside of it. The increase in spending is across the board, with strong increases in the former Soviet Union and CIS countries (42%), Latin America (21%), and Africa (14%), and smaller increases in Europe and the Middle East. Latin America is seeing aggressive E&P spending by Brazil’s Petrobras, Colombia’s Ecopetrol, and Mexico’s Pemex. Mexico is trying to reverse rapidly declining production rates and Colombia is trying to jump-start an upstream profile that has largely languished since the mid-1990s. Brazil is forging ahead with its promising pre-salt development. Other large upstream spenders this year are expected to be ExxonMobil, PetroChina, Lukoil, and Chevron.

The survey said that oil and gas companies were basing their 2012 capital spending budgets on an average oil price of USD 87 a barrel for West Texas Intermediate and USD 98 a barrel for Brent. Global benchmark Brent was set to finish 2011 at its highest annual average price, in both real and nominal terms, since the modern oil industry began, according to an IHS Cambridge Energy Research Associates analysis released just before the end of the year. Continued strong global demand, concerns about sup-ply constraints in some regions, and higher production costs all combined to support the record-level price. Brent was expected to average USD 111/bbl last year.

In short, the supply/demand balance and higher labor and material costs are driving the highest prices. Upstream production in challenging areas is also a factor. Drilling in North America should continue to be strong, although low natural gas prices have caused companies to shift away from gas and toward liquids plays. Companies responding in the Barclay’s survey said that the biggest factor in determining their North American activity was oil prices, followed by gas prices and then cash flow. Spending growth in North America is forecast to last until at least 2015.
The Tantalizing Promise of Oil Shale
Authors: Beckwith Robin
Published: February 2015

Oil Shale

A vast energy treasure lies within an 18,963-sq-mile area of Colorado, Utah, and Wyoming: an estimated 4.28 trillion BOE of in-place resources of oil shale, according to US Geological Survey (USGS) research geologist Ronald Johnson. He presented the new assessment at the 31st Oil Shale Symposium, held mid-October 2011 at the Colorado School of Mines.

In other countries, while far fewer oil shale resources are thought to exist, their presence is nonetheless formidable. China contains an estimated 333 billion BOE; Russia, 248 billion BOE; Democratic Republic of Congo, 100 billion BOE; Jordan, 90 billion BOE; Brazil, 82 billion BOE; Italy, 73 billion BOE; Morocco, 53 billion BOE; Australia, 32  billion BOE; and Estonia, 16 billion BOE. Israel indicated at the 30th Oil Shale Symposium that its resources may be as much as 250 billion BOE.

The CIA World Factbook estimates 2011 world proved reserves of crude oil at 1.47 trillion bbl. Total annual production of oil shale in the only three countries today where it is exploited for commercial use is 73% less than daily worldwide crude oil production of approximately 86.74 million B/D.

With oil shale estimates vastly overshadowing those for crude oil, why does oil shale remain a scarcely touched resource?

The Bottom Line

“In-place resources” and “proved reserves” have markedly different meanings. The former speaks of potential; only the latter indicates the existence of hydrocarbons that can be exploited economically. “No attempt was made to estimate the amount of oil that is economically recoverable,” explains the USGS in the introduction to its 2011 assessment of US Greater Green River Basin oil shale resources, “because there has not yet been an economic method developed to recover the oil from … oil shale.” This statement might be amended, says Center for Oil Shale Technology and Research (COSTAR) director Jeremy Boak, to reflect a view that current producers might suggest, ’whereby, while methods have been developed to recover the oil from oil shale, none has yet demonstrated commercial production of Green River formation shale oil.”
Taking Advantage of Vessels of Opportunity
Authors: JPT staff _
Published: February 2015

Colin Buchan’s job at Shell is to find ways to find other vessels of opportunity—offshore construction vessels adapted to do what drilling rigs are not so well equipped to do faster and for less.

I think it was one size fits all before. A drilling rig is what you used,” Buchan said. “Now there are more options there to pick from.” His job title, well delivery manager for floating hoist at Shell, is an indication of what the options look like. Hoisting is a reference to many devices lowered to the bottom using a wireline, rather than sending them down to the well through a riser.

“We’re not seeing drilling rigs going out of business,” he said. But the high cost of repairing wells using drilling rigs and their limited number compared with the number of subsea well completions both argue for new approaches.

The goal is to do as much as possible to improve production from subsea wells by expanding the roles of vessels now doing deepwater construction work, such as installing manifolds or anchors on the seafloor. Construction vessels would play a growing role, from wellsite preparation through completions and maintenance, to plugging and abandonment.

Wireline well interventions have become common in the North Sea and will be moving to deep water. Offshore Brazil construction boats are coming in behind drilling rigs to complete wells by installing production hardware, such as subsea trees to control the flow and connecting them into the production system.

The high cost of drilling, completions, and repairs has a direct bearing on the ultimate output of reservoirs. To ensure the ultimate return exceeds the ultimate cost over the life of the well, operators will only develop discoveries with 150 million bbl of recoverable reserves or more into production, said Keith Millheim, managing director of Nautilus International. He, along with others, has started a pair of companies to commercialize a self-standing riser technology that he says will reduce costs sufficiently to change how deepwater fields are managed.

One of the companies, MEPS First Oil, is focused on reducing the cost of extended well tests and reducing the time it takes to begin production. More testing could reduce the risk that a field will fall short of expectations because of an incomplete understanding of a reservoir.

Significantly reducing the cost of field evaluation, construction, maintenance, and production could expand the universe of deepwater fields that can be profitably produced. Millheim estimates that there are 3,000 deepwater fields globally with less than 50 million bbl of reserves that cannot be produced without shifting the cost curve to allow more testing, maintenance, and artificial lift to be used.
Seria Field, Brunei: 80 Years On - Near-Field Exploration Going Strong
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 15199, ’The Seria Field, Brunei: 80 Years on, Near-Field Exploration Going Strong,’ by John Church, SPE, and Bong Poh Yuk, Brunei Shell Petroleum, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, 15-17 November. The paper has not been peer reviewed. [Note: Conference rescheduled to 7-9 February 2012.] Copyright 2011 International Petroleum Technology Conference. Reproduced by permission.

The onshore Seria oil field in Brunei was discovered in 1929 and has produced more than 1.1 billion bbl. The field still has a large near-field-exploration (NFE) portfolio of undeveloped reservoir blocks on the northern flank. These blocks, under the shallow marine surf zone, have been difficult to access because of the very shallow water and shoreward-dipping nature of the fault blocks. However, the Seria North Flank (SNF) project has begun to unlock these volumes by implementing the fishhook-well concept, allowing these opportunities to be developed from land. 

Introduction

The Seria oil field is a complexly faulted anticlinal structure with hydrocarbons trapped behind fault/dip structures in stacked deltaic sediments. The field straddles the coastline, with the northern half of the field offshore under shallow water. Early oil production was dominated by wells drilled on land. Production peaked at approximately 120,000 BOPD in 1956. The field production declined throughout the 1960s and much of the 1970s. Since 1990, the field has been producing approximately 20,000 BOPD.

The northern flank of the Seria anticline was known to hold hydrocarbons, but the shallow surf zone made drilling rig access problematic. Poor-quality seismic data had limited development activity. Several penetrations had been made by use of deviated wells drilled from shore, which passed orthogonally through the shoreward-dipping fault blocks with only limited and suboptimal reservoir penetration. The potential was known, but underexploited.

SNF Project (2004–09)

New high-resolution 3D seismic over the shallow marine surf zone was acquired in 1998 that identified a large number of undrilled blocks on the north flank of the Seria anticline. Exploration drilling began in 2004, with the discovery of the first block on the SNF. Follow-up drilling led to further discoveries in adjacent blocks in 2005 and 2006.
Doubling Production From a Mature North Kuwait Reservoir
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 15334, ’Doubling the Production From a Mature Reservoir in North Kuwait - Challenges, Achievements, and Lessons Learned,’ by H.B. Chetri, SPE, M. Raju, SPE, Harry Alam, SPE, and Hussain Al-Ajmi, SPE, KOC, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, 15-17 November. The paper has not been peer reviewed. [Note: Conference rescheduled to 7-9 February 2012.] Copyright 2011 International Petroleum Technology Conference. Reproduced by permission.

Sabiriyah Lower Burgan (SA LB) is a clastic reservoir in northern Kuwait that has been on continuous production for 45 years. The reservoir, with an active waterdrive, suffers from a rapid increase in watercut. Production performance of the wells declines dramatically after the water cut reaches 40%. The formal strategy for production had been focused on keeping the active perforations away from water. In the past, the concern was to avoid installation of artificial lift or the application of water-shutoff or new technologies. 

Introduction

The SA LB reservoir is a prolific reservoir with natural-aquifer support. The crude is light, at 33°API, and has less than 2.8% sulfur. Cumulative production is approximately 40% of reserves. The reservoir has produced only by natural flow at a daily rate for the last 3 to 4 years of approximately 50,000 BOPD, with average water cut of 29%.

The team works daily to review and identify perforation intervals that could improve well performance. Also, the well reviews aim at identifying and implementing suitable water-shutoff jobs for improving the production performance. Therefore, close production monitoring, tracking of water movement, and use of surveillance techniques (e.g., production-logging tools) are key to the success of these production-management efforts. Geologically, water movement resulting from cumulative depletion has led to tortuous movement of the water front, which requires periodic mapping and integrating with production activities. Crossflow between layers, caused by inappropriate perforating procedures, also results in underperforming wells.

To double production from the reservoir within 6 months, the following actions were taken.

Extensive review of the well performance

Intelligent analysis of existing wells

Identification of production-enhancement opportunities (with reference to mapping resources needed), use of horizontal wells, and first-time installation of electrical submersible pumps (ESPs)  

More-ambitious ESP implementation than was contemplated earlier.
Kick-Tolerance Misconceptions and Consequences for Well Design
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140113, ’Kick-Tolerance Misconceptions and Consequences for Well Design,’ by Helio Santos, SPE, Erdem Catak, SPE, and Sandeep Valluri, Safekick, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed.

Kick tolerance defines the appropriate number and setting depths of casing strings required to achieve drilling objectives. It also is used during drilling to determine whether it is safe to continue drilling or if there is a need to run a casing string. Alternatively, it is used to indicate whether it is safe to circulate a kick out of the well or whether bullheading is necessary. During development of a new well-control system, a thorough review of the fundamental concepts involved was carried out, and, in relation to kick tolerance, a few misconceptions were identified.

Introduction

Even though kick tolerance is a critical and fundamental concept for the drilling industry, there is no standard used by operators, drilling contractors, or training institutions. Hence, there are several definitions of kick tolerance and different ways of calculating it. This lack of consistency may be why the subject is not well understood and, there-fore, is sometimes used dangerously. Definitions of kick tolerance may be in terms of pit gain, mud-weight increase, or underbalance pressure.

Another point of disagreement is on how the predicted pore pressure should be used in calculations. Some companies use a value greater than the mud weight, while others use a value greater than the predicted pore pressure. Despite the variations, the goal is consistent: to use a procedure that ensures safe drilling of a well. Often, this lack of a standard and of under-standing the topic leads to uncertainty and discussions during drilling. Questions often arise regarding whether it is safe to continue drilling. Because wells are now drilled in more-challenging environments, such as high-pressure/high-temperature and deep and ultradeep water, a small variation in the way that kick tolerance is calculated can lead to premature abandonment of the well or, worse, to a hazardous drilling situation.

Kick-Tolerance Calculation—Current Approach

The first step of a simplified kick-tolerance calculation (i.e., constant temperature, constant density, and no compressibility) is to define the maximum vertical height of a gas influx Hmax at the casing shoe (assumed to be the weakest point in the open hole). Hmax is deter-mined on the basis of fracture gradient; mud weight; kick-fluid density; predicted pore pressure; and adjusted maximum allowable annular surface pressure (MAASP), which is reduced by a safety margin. What is conceptually wrong is that if the bottomhole-assembly (BHA) length is greater than Hmax, the kick cannot be circulated out of the wellbore because it will reach the top of the drill collars with a kick height greater than Hmax, which would induce losses at the shoe.
Open Innovation: From Its Beginning to Today
Authors: Bernstein Ed
Published: February 2015

Guest editorial

In our constantly changing world, corporations find themselves continually adapting to new trends and technologies, and often reinventing themselves to remain relevant. In fact, with our changing global business environment, staying the course is not an option if today’s businesses want to remain viable and competitive.

One of the most dramatic corporate shifts we have seen over the last decade is on the innovation front. As recently as the early 2000s, innovation was largely derived from within an individual corporation’s walls through its internal research and development (R&D) departments. However, as the pace and intensity of competition around the globe increased, it was widely becoming recognized that to maintain and increase a competitive edge, R&D strategies were going to have to change.

In 2003, Henry Chesbrough wrote about a new collaborative innovation theory and coined it “open innovation,” which he defines as “the use of purposive inflows and outflows of knowledge to accelerate internal innovation and expand the markets for external use of innovation.” He further explains that the open innovation paradigm can be understood as the antithesis of the traditional vertical integration model in which internal innovation activities lead to internally developed products and services that are then distributed by the firm (Chesbrough 2012). The roots of this concept date back almost a decade prior to Chesbrough’s research, to discussions and meetings at the Industrial Research Institute with members like Procter & Gamble (P&G) and General Electric (GE) sharing best practices on how to succeed in R&D’s ever-changing environment.

It is not a coincidence that at the same time our innovation model was beginning to change, the Internet and emergence of social media were enabling society as a whole to be more connected and helping to facilitate collaboration across geographies. In the same year as Chesbrough, the widely regarded founding father of open innovation, presented his theory, LinkedIn was introduced; Facebook debuted a year later and at the end of June 2012 was reporting an astounding 955 million monthly active users; Twitter was launched in July 2006 and today has more than 500 million active users. 

Not surprisingly, leaders at major corporations in various industries were recognizing that the world was becoming increasingly connected and perhaps the most effective and efficient path to innovation was no longer through internal channels and limited company resources. The concept of open innovation progressively began to infiltrate corporate R&D practices and today has claimed a prominent position in our corporate culture as a compelling and effective force behind creating new concepts and products.

Procter & Gamble was one of the first companies to explore using external sources for innovation. Its approach, Connect + Develop, was first presented in 2000 at a fall meeting of the Industrial Research Institute, and would become P&G’s open innovation program.
Sustainable Energy Growth Tops Middle East Conference Agenda
Authors: Henni Abdelghani
Published: February 2015

Conference review

The 15th annual Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC), organized in the capital of the United Arab Emirates, attracted major national and international oil and gas companies from around the world to discuss common challenges and the opportunities in the region.

Involvement from Middle Eastern countries was higher than ever at the conference, with delegations from Saudi Aramco, Qatar Petroleum, Kuwait Petroleum, Sonatrach, and many other international companies discussing their strategies and technologies.

The largest oil and gas show outside North America were held under the theme “Sustainable Energy Growth: People, Responsibility and Innovation.” More than 50,000 people from 91 countries attended.

SPE organized the conference and technical sessions, which covered a number of topics that influence the industry including technical, economic, personal skills, and capability issues. More than 50 technical sessions presented by 300 industry experts were delivered during the event.

Mohamed Bin Dha’en Al Hamli, UAE minister of energy, opened the ADIPEC conference. He said the scale of ADI-PEC and its setting in Abu Dhabi made it an ideal platform to address the complex technical and logistical challenges of exploring for and producing oil and gas at a time of increasing global energy demand.

Formally introducing the conference, Ali Rashid Al Jarwan, chief executive officer of Abu Dhabi Marine Operating Company (Adma-Opco) and chairman of the ADIPEC 2012 conference, said the itinerary was the most comprehensive to date. “This year, the event offered more depth and scope than ever before. ADIPEC was founded on the principle of sharing knowledge and experience. This principle is as relevant now as it was 25 years ago when ADIPEC was established,” he said.

Speaking on the challenges of growing global energy demand, Christophe de Margerie, chief executive officer of Total, said that demand for oil and gas from non-OECD countries has increased and this creates a challenge. “Meeting the increasing demand is a bit challenging due to projects’ complexity, access to finance, and geopolitical constraints,” de Margerie said. “To meet this soaring demand, new LNG (liquefied natural gas) projects are needed to satisfy European and Asian demand, even with potential additional supply from shale gas.”

To address the new challenges facing the industry, companies should focus on leveraging technology, he said. “This will help unlock resources and improve recovery, optimal development through innovation, as well as operational excellence,” he said.

Sami Al Rushaid, chairman and managing director of Kuwait Oil Company, said that his company is strongly focusing on optimizing recovery through primary, secondary, unconventional, enhanced oil recovery (EOR), and development of heavy oil. “Significant oil is also expected to come from exploration activities,” he said.
Structured Mentoring: A Critical Component of a Global Talent Management Strategy
Authors: Rousseau Meta
Published: February 2015

Talent & Technology

Competing for market share in a dynamic international marketplace, the front-runners are those who are able to build a skilled, global workforce through multifaceted strategies that enable them to align training, mentoring, and coaching initiatives and implement cutting-edge practices such as social and mobile learning. Structured mentoring forms the foundation of a well-designed talent management strategy. Well-designed mentoring programs enable organizations to align and seamlessly integrate training, coaching, and mentoring initiatives into holistic, personalized offerings. It is through successful structured mentoring programs that organizations are able to sustain a uniquely skilled and internally motivated workforce that sets them apart from their competition.

Before looking at structured mentoring as a key learning strategy and overarching component of a comprehensive talent management strategy, briefly consider the components that form part of the typical organization’s talent management strategy. Structured mentoring affects each in a slightly different way.

1. Talent Acquisition. A good mentoring program is a powerful recruiting tool. Candidates tend to associate the quality of an organization’s professional development programs with future career opportunities.

2. Performance Management. Mentoring allows for the development of professional and personal relationships that facilitate internal motivation, effective teamwork and the timely and successful completion of performance objectives and realization of business goals.

3. Training and Development. Mentoring programs do not replace but complement training initiatives and allow for the development of tacit knowledge and complex skills that cannot be honed in any other way.

4. Talent Retention. Employee surveys and research studies suggest that employees who are involved in mentoring programs are more likely to report job satisfaction and less likely to seek other opportunities. Mentoring programs that span international boundaries also aid global mobility and increase the availability of attractive career opportunities.

5. Succession Planning. Mentoring programs seek and are supported by vibrant communities of practice that provide talent managers with the ability to identify talent pools from which positions could be effectively filled.

While mentoring adds value to the overall talent management program, its effect is most visible in professional development. When we look at mentoring as a professional development or learning strategy, we need to consider the mentoring in relationship with training and clarify similarities and differences. Four simple definitions as shown in Table 1 may be helpful.
CO2-EOR Mobility and Conformance Control: 40 Years of Research and Pilot Tests
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 154122, ’Mobility and Conformance Control for CO2 EOR - Thickeners, Foams, and Gels: A Literature Review of 40 Years of Research and Pilot Tests,’ by R.M. Enick, SPE, University of Pittsburgh; D. Olsen, SPE, IBM Global Business Services; J. Ammer, US Department of Energy, National Energy Technology Laboratory; and W. Schuller, URS Corporation, prepared for the 2012 SPE Improved Oil Recovery Symposium, Tulsa, 14-18 April. The paper has not been peer reviewed.

Carbon dioxide (CO2) has been used commercially for enhanced oil recovery (EOR) for more than 40 years. The CO2-EOR process could be improved if the high mobility of CO2 relative to reservoir oil and water could be reduced effectively and affordably. The water-alternating-with-gas (WAG) technology is the preferred method to control CO2 mobility, along with the use of mechanical techniques (e.g., cement, packers, well control, infield drilling, and horizontal wells) to help control the CO2-flood conformance. If the next-generation CO2-EOR target of 67 billion bbl is to be realized, new solutions are needed that can recover significantly more oil than the 10–20% of the original oil in place (OOIP) associated with current flooding practices. This literature review concentrated on the history and development of CO2-mobility-control and profile-modification technologies.

Introduction

Every day, more than 110 field projects in the US, 60% of which are in the Permian Basin in west Texas, inject 3.1 Bscf of CO2 into sandstone and carbonate formations to recover more than 280,000 bbl of oil. This corresponds to approximately 5% of the nearly 5 million BOPD of US oil production. The number of CO2-flood projects has increased steadily in recent years, in contrast to other EOR methods. The limiting factor for expanding CO2 flooding is the availability of large volumes of high-pressure CO2 because most CO2 suppliers are operating at full capacity. For example, new projects in the Permian Basin are constrained by the need for an additional 0.3–0.4 Bscf/D of CO2 in the region. Conversely, the rapid growth of CO2 EOR in Mississippi reflects the growth of CO2 supplies in that region.

Approximately 74.4% of the CO2 used for EOR comes from gas-treating and -processing facilities associated with the production of CO2-rich natural gas, while 19.4% originates from natural-gas plants, 4.8% from coal-synfuel plants, and the remainder from various chemical and petroleum facilities. The dehydrated, high-pressure CO2 from various sources is transported to oil fields where it is compressed to the desired injection pressure, combined with recycled CO2 and injected into the reservoir.