bluuebunny/crossref_metadata_2025 huggingface dataset:
Overview: Mature Field Revitalization (January 2007)
Authors: Lagerlef David
Published: February 2015

Every mature field has unique characteristics, and, often, several viable options for revitalization stand out. However, pursuing some options eliminates attempting alternatives. Once a decision is made to implement some revitalization options, it is very expensive, if not impossible, to change course and attempt alternatives that had been identified earlier in the evaluation process. The risk of high costs or pursuing the wrong alternatives must be minimized because, even at higher oil prices, many revitalization projects are marginally economic. Obtaining information specific to the mature field can contribute to reducing these risks. Simulations and pilot projects can use data effectively to narrow down options. Often, though, economic limits constrain how much actual data can be gathered. Thus, previous experience in revitalizing similar types of fields can be very leveraging for mature fields.

SPE membership provides access to archived SPE papers, which can be used to help identify and rank revitalization alternatives. The papers presented in this section are, in many ways, representative of all the papers presented in the last 12 months from which these four were selected. Literally thousands of other SPE papers have been presented over the last few years, providing useful details regarding the success and challenges of hundreds of revitalization techniques. The most recent technical papers include current details on the use of best available technology to revitalize mature fields around the world.

The technology behind revitalization techniques presented in papers more than a year old may be slightly out of date, but much can be learned by reviewing the approach taken to investigate potential solutions, the types of options considered, and the progression from ideas to realities presented in the papers. Just as petroleum-engineering tools advance over time, techniques for revitalizing mature fields improve as lessons are learned from past experiences. Incredible knowledge-sharing dividends are available to SPE members aware of previous work performed in mature fields similar to those fields that now need to be revitalized.

Mature Field Revitalization additional reading available at the SPE eLibrary: www.spe.org

SPE 100024 "Making Our Mature Fields Smarter—An Industry wide Position Paper From the 2005 SPE Forum" by R. Murray, SPE, BP plc, et al. [See JPT (August 2006) 49]

SPE 99948 "Integrated Multizone Low-Cost Intelligent Completion for Mature Fields" by H.L. da C.P. Pinto, Petrobras, et al.

SPE 102964 "The Origin and Resource Potential of Residual Oil Zones" by L.S. Melzer, Melzer Consulting, et al.

SPE 99706 "Enhancing Oil Production From Mature Fields by Focusing on Well-Intervention Management: North Oman" by A. Al-Bimani, SPE, Petroleum Development Oman, et al.
Q&A with Thamir Abbas Ghadhban
Authors: Ghadhban Thamir Abbas , Donnelly John
Published: February 2015

Q&A

What is Iraq's current oil production and reserves?

Oil production in Iraq is currently about 2.25 million BOPD, with production capacity of 2.8 million BOPD. There has been a recent increase of some 300,000 BOPD because of the resumption of exports of oil in the north through Turkey after the government succeeded in securing the export pipeline. Exports are now about 1.85 million BOPD. Our production target for 2008 is 2.5 million BOPD. Iraq's oil reserves are between 112 and 115 billion bbl of proved reserves.

What is the current status of the hydrocarbons law, which you helped to draft?

Right now it is in Parliament, in the Council of Representatives. There has been a delay on this law for various reasons, some of which are administrative—the council was on holiday for a month in August, and there are other laws pending that require debate. But I expect discussion on the hydrocarbons law to begin soon.

What are the main objections to the law by its opponents?

There have been some differences between the federal government and the regional government of Kurdistan on some details, but they are not of a serious nature. It is not about ownership of the oil but about authority. The ownership question has been solved—oil and gas are the property of the whole nation of Iraq. There is some disagreement about the nature of contracts, particularly production sharing. But the main political parties in the government favor the law.

If the law passes, what role will there be for international oil companies (IOCs) in Iraq?

There is no doubt there will be a big role for IOCs because there is a recognition in Iraq that there is a great need for technology, managerial skills, and speedy development of oil and gas fields. There is agreement that IOCs will have a role. The disagreement is over what type of role or what form of contracts will be implemented.

I would expect that in the coming years, and especially next year, there will be room for IOCs to start taking an active role in oilfield development and exploration. The country's major resources are oil and gas, and the revenue from oil exports constitutes more than 90% of the federal budget. The government is aware that oil and gas development and expansion are priorities for the country, and for speedy development of production capacity and export capacity, the involvement of IOCs is essential.
Examining Marine Safety Operations
Authors: Strong Philip
Published: February 2015

Management

Millions of crew transfers must be carried out around the world each year to keep the offshore industry going. Crew supply is one of the highest-risk activities in offshore operations, whether passengers are moved by helicopter or boat. Historically, risk management for marine-based crew supply has received little priority, and a lack of reliable information has generated misconceptions about the true risks and has masked breakthroughs. However, many operators are now attaching a high level of importance to all crew-supply activities. Exceptional progress has been made in the development of safer, more efficient alternatives, with operators, vessel owners, and transfer specialists all making important contributions.

Many operators are now looking more closely at their crew-supply options and are re-evaluating established methods. Choices are being influenced by a number of factors, such as cost, downtime risk, passenger comfort, journey times, and safety. A new generation of high-speed crew-supply vessels brings the prospect of fast, efficient, and safe vessel-based crew supply to the industry, which may place even greater focus on the evaluation of these operations.

For industry professionals to make appropriate choices and to drive safety improvements, they need a good appreciation of the risks. In vessel-based crew supply, the crane-transfer operation is widely accepted as the key safety concern. A scarcity of data both on activity levels and on incidents has made it difficult to develop a clear picture of safety performance. However, in the past few years, progress has been made. A major US operator and a major international vessel company have shared their personnel-transfer-incident data with Reflex Marine, and these incidents were added to an existing database gathered from public sites, including the US Minerals Management Service, the Petroleum Safety Authority in Norway, and the UK Health and Safety Executive, as well as from private reports.

It is estimated that more than 5 million crane transfers take place each year, a large-scale activity of an order comparable to the numbers moved by helicopter. The collated sample data include more than 60 crane-transfer incidents, resulting in 48 injuries and seven fatalities. Of those incidents, most of which occurred within the past 10 years, 32% involved lateral impact, 40% falling, 23% heavy landing, and 5% immersion. Although crane transfers are rightly regarded as a high-risk operation, it is important to view this in the wider context. The data indicate that the level of fatalities (per crew transfer) is lower than for helicopters, although injury rates are considerably higher.
Success of SAG-Foam Processes in Heterogeneous Reservoirs
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110408, "Success of SAG-Foam Processes in Heterogeneous Reservoirs," by W.J. Renkema and W.R. Rossen, Delft University of Technology, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November.

In principle, miscible-gas injection can displace nearly all of the oil from the portions of a reservoir swept by gas. However, reservoir heterogeneity, low gas density, and high gas mobility reduce sweep efficiency and decrease recovery drastically. The use of foam can reduce gas mobility and the effect of heterogeneity, thereby increasing sweep efficiency. An optimal design strategy is proposed for surfactant-alternating-gas (SAG) -foam processes.

Introduction

Primary- and secondary-recovery methods leave behind up to two-thirds of the oil originally in place in the reservoir. Gas injection can increase the recovery from depleted reservoirs. Injected gas tends to rise to the top of the reservoir because of its low density, then over-ride the oil-rich zone, leading to early gas breakthrough. High mobility of the gas leads to viscous instability, which enhances gravity override and makes heterogeneity much worse by forming high-mobility flow paths.

The use of foam for mobility control, proposed in 1958, traps some bubbles and reduces movement of flowing gas, thereby reducing gas mobility. Trapped gas reduces gas relative permeability because foam films (lamellae) block some of the flow channels. In flowing bubbles, the effective gas viscosity is increased because pore walls and constrictions cause significant drag. Foam does not change the water relative permeability function or liquid viscosity.

Foam can be injected into the reservoir by coinjection of gas and water or by SAG injection (alternating slugs of surfactant solution and gas). For CO2-foam projects, the SAG process also reduces corrosion in surface facilities and pipe. In low-permeability porous media, the SAG process increases gas injectivity. When gas is injected, water is displaced from the near-well region farther into the reservoir, weakening foam near the well. As a result, gas mobility in the near-well region rises, and injectivity increases.

Foam Model

Existing models can be divided into local-steady-state models (ranging from simple to more-complex semimechanistic models) and dynamic "population-balance" models. Population-balance models take into account the rate of change of foam texture (i.e., bubble density), which depends on creation, destruction, and trapping of lamellae.

Local-steady-state models use an algebraic relation (which could be empirical or more physically based) between gas mobility and factors determining foam texture (e.g., surfactant concentration). All these models account for foam having no effect on the relative permeability function for water.
Production Enhancement in a Brownfield Redevelopment Plan
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101491, "An Approach for Production-Enhancement Opportunities in a Brownfield Redevelopment Plan," by Antonio Cuauro, SPE, Schlumberger; Mohd Izat Ali, SPE, and Maharon Bin Jadid, SPE, Petronas Carigali Sdn. Bhd.; and Ekrem Kasap, SPE, (now with Shell E&P) and Torsten Friedel, SPE, Schlumberger, prepared for the 2006 SPE Russian Oil and Gas Technical Conference and Exhibition, Moscow, 3–6 October.

The Betty oil field was discovered in 1968 and has produced since 1978. With the objective of rejuvenating the asset, a multidisciplinary optimization team was built. The standard practices to evaluate production-enhancement opportunities include logging, nodal analysis, and well-engineering technologies. Usually, the older the field, the more challenging it is to achieve additional reserves. The full-length paper outlines an integrated approach for achieving these objectives, reducing the risk associated with the various enhancement alternatives.

Introduction

Brownfields have been defined as mature fields with declining production or at the end of their productive lives. Such fields contain resources that are needed by the countries they belong to and by the world economy. These brownfields generally are more than 30 years old and account for 67 to 72% of world production.

The Betty field was discovered in 1968 by the Betty-1 well, 25 miles offshore from Lutong, Malaysia, in the Baram Delta. A 24-slot drilling platform was installed in 1978, from which nine development wells were drilled. Two other structures house the separation facilities and a flare boom.

Three "revisit" campaigns were con-ducted on the Betty field. The first, in 1984, drilled five additional wells. The second campaign, in 1988, drilled 10 additional wells and worked over two existing wells. The third revisit was in 1994, to sidetrack four wells. There are eight reservoirs that have been targeted and produced. All of the wells are dual-string completions with two or more perforated intervals.

With the objective of rejuvenating the field, Petronas Carigali and Schlumberger joined forces to improve recovery from this mature field. A multidisciplinary team was assembled, and the collective approach to meet this objective focused on engineering and geology. Production enhancement involves several techniques to improve well performance, such as fracturing, acidizing, perforating, and artificial lift. The way to achieve the maximum productivity of a well is determined by the quality and quantity of data for that well.

Because field-development plans involve multiple objectives, the full-length paper details the well-engineering part, focusing on production-enhancement strategies. Determination of the estimated ultimate recovery (EUR) and the location of these reserves used both numerical simulation and nodal analysis, which are key to this integrated approach. The integrated approach was used to reduce uncertainties and risks associated with proposed activities.
Reviving the Mature Handil Field: From Integrated Reservoir Study to Field Application
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110882, "Reviving the Mature Handil Field: From Integrated Reservoir Study to Field Application," by Henricus Herwin, SPE, Emmanuel Cassou, SPE, and Hotma Yusuf, SPE, Total E&P Indonesie, prepared for the 2007 SPE Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, 30 October-1 November.

The Handil field, discovered in 1974, is a giant mature oil field in the Mahakam Delta of Indonesia. Fieldwide production declined from 200,000 BOPD in the late 1970s to 12,500 BOPD in 2003. An integrated study on the largest gas-injection reservoir was performed to assess project performance. An intensive light-workover (LWO) campaign was launched, and three pilot wells, each with a different type of completion, were put on production successfully. Infill drilling and optimization of an enhanced-oil-recovery (EOR) project also were implemented. Fieldwide production increased to 23,000 BOPD.

Introduction

As Fig. 1 shows, the Handil field comprises 555 unconnected accumulations (reservoirs) in structurally stacked and compartmentalized deltaic sands. The reservoirs are trapped by the Handil anticline, which is cut by a major impermeable fault dividing the field into two compartments: north and south.

The reservoirs are between 200 and 3500 m subsea and cover an area 10 km long by 4 km wide.

Three reservoir characteristics distinguish the field.Shallow zone: This zone is as deep as 1500 m subsea, with excellent permeability ranging from 200 to 2,000 md and with very strong aquifers that maintain the reservoir pressure at initial condition. However, the sands are poorly consolidated, requiring sand-control techniques.Main zone: This zone is between 1500 and 2200 m subsea, with permeability between 10 and 500 md. Most reservoirs had initial-gas caps, which have been pre-served to maintain the reservoir pressure, especially because the aquifers are not as strong as those for the shallow reservoirs. The sands are normally well consolidated; therefore, sand production is not an issue.Deep zone: This zone is below 2200 m subsea, contains mostly gas, and decreases in quality with depth to a permeability of several millidarcies.

Production History

To maintain production and reservoir pressure, water injection was started in 1978, which maintained the 160,000 BOPD production until 1985. Gas lift was introduced in 1979 and was implemented fieldwide in 1991. Infill drilling has helped maintain production. More than 350 wells have been drilled in the field, with an average spacing of 300 m. In November 1995, a lean-gas-injection project was initiated in five reservoirs. The project boosted the production of the five large reservoirs and altered the overall decline rate of the field. Therefore, the project was extended in 2000 to six other large reservoirs, which resulted in more than 25% of the field reserves being under a tertiary-recovery mechanism. In 2003, field production had declined to 12,500 BOPD.
Wellbore-Strengthening Technique for Drilling Operations
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105809, "Further Development, Field Testing, and Application of the Wellbore- Strengthening Technique for Drilling Operations," by Giin-Fa Fuh, SPE, and Dave Beardmore, SPE, ConocoPhillips Co., and Nobuo Morita, SPE, Waseda U., prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20-22 February.

A significant increase in formation fracture resistance can be achieved as a result of a fracture sealing or plugging mechanism induced by a particle "screenout" effect resulting from the drilling fluid being loaded with an adequate amount of narrowly sized granular materials. Such an increase in formation fracture resistance is particularly valuable in helping to drill through depleted zones without losing fluid, strengthening the weaker formations that usually require additional casing strings for protection, avoiding lost circulation during cementing operations, and drilling high-angle well sections with high mud weights that normally would not be possible because of low formation fracture gradients.

Introduction

Lost circulation is perhaps the most costly mud-related drilling problem. Not only is rig time lost, but large volumes of expensive drilling fluids are lost to the formation. Lost circulation also can lead to severe well-control incidents. In response, several technologies referred to as "wellbore strengthening" (WS) are being developed to prevent or correct lost circulation. WS means that the breakdown pressure of the wellbore is greater after the treatment than before. These methods include use of special granular material, heating the wellbore, and use of rigid-plug-forming pills. The full-length paper focuses on a WS method that uses mud with special bridging and fluid-loss formulations.

In the mid-1980s, a joint-industry project (JIP) was conducted to determine why oil-based mud apparently caused a lower fracture gradient than water-based mud (WBM). Data from this JIP were analyzed, and it was determined that they did not fit ordinary fracturing models of the time. These researchers noted that certain lost-circulation materials (LCMs) actually seemed to increase the pressure required for fracture propagation to more than what was seen with untreated drilling mud. They conducted laboratory tests outside the JIP to verify their observations. The result was the development of a loss-prevention material (LPM) that was found to inhibit the extension of a fracture tip.

LPM was tested in the field several times and was quite successful. It was able to increase the wellbore break-down pressure in several cases, and subsequent application of the technology has allowed a casing string to be skipped in several cases. The technique affects only the near-wellbore break-down pressure, not the far-field fracture gradient.
Wellbore Strengthening in Shale
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110713, "A New Treatment for Wellbore Strengthening in Shale," by Mark S. Aston, SPE, Mark W. Alberty, SPE, and Simon Duncum, BP plc, and James E. Friedheim, SPE, and Mark W. Sanders, SPE, M-I Swaco, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November.

The full-length paper demonstrates that wellbore strengthening in shale is feasible. A treatment pill was developed in the laboratory and field tested successfully at a US land-based location. The treatment consisted of a blend of particulates (known as stress-cage solids) and proprietary crosslinked gelling polymers that set with time. Properties of the system such as compressive strength, adhesion to shale, and sensitivity to temperature and pressure were evaluated. Modeling work was conducted to engineer the size and concentration of bridging solids required.

Introduction

Drilling in depleted zones, or intervals where high-pressured formations are interbedded with normally and abnormally pressured layers, has created the need for these strengthening technologies. The goal is to increase the fracture resistance of weaker formations and thereby avoid mud losses, wellbore instabilities, and the potential loss of the drilled interval. The primary consequences of these undesired events are an increase in nonproductive time and associated costs. In addition to avoiding these problems, the economic benefits that wellbore strengthening can provide are the possible elimination of a casing string or, more importantly, the ability to reach deeper reservoir targets.

One of the most popular wellbore-strengthening technologies is inducing an increase in wellbore stresses by use of sized-particulate additions to the drilling fluid. The common name for this approach is "stress caging." The principle is to increase the hoop stress around the wellbore by using fractures to cause stress changes in the rock. These fractures would be held open with bridging material, thereby creating the stress-cage effect, or strengthening of the wellbore. This bridge of particles across the mouth of the fracture must have low permeability to provide pressure isolation of the fluid in the wellbore from that in the fracture, thus preventing any further fracture elongation. The degree of stress caging relative to the native stresses is a function of both fracture width and radius and the rock properties (i.e., Young's modulus and Poisson's ratio). To achieve this effect, the proper type, size, and amount of loss-prevention material (LPM) must be used. Using the stress-cage concept and associated factors, drilling fluids can be designed to maximize this strengthening effect and minimize losses and other problems encountered when drilling significantly above the fracture gradient. In fact, use of these LPMs for wellbore strengthening has led to several complementary technologies.
Techbits: Technology Strategies Highlighted at Norway Conference
Authors: Moon Ted
Published: February 2015

Techbits

From 15 to 16 October, more than 120 oil and gas professionals converged in Bergen, Norway for the fourth SPE Norwegian Petroleum Technology Conference (PTC). The conference, which was held in conjunction with Norway's Offshore Technology Days Exhibition, allowed managers, engineers, and business development planners to discuss how Norway plans to maintain its status as a global energy technology leader and incorporate innovations from companies big and small, far and wide.

"The conference was really focused around StatoilHydro's dominant role in the Norwegian oil and gas industry and how they plan to ensure continual development of new technologies and put them to use," said Jan Roar Drechsler, Chairperson of the PTC Program Committee and the SPE Stavanger section, as well as a Principal Engineer and Technical Representative for Completions with StatoilHydro. "In the past [prior to the merger of Statoil and Norsk Hydro], there was a sort of competition between Statoil and Hydro to be first in the development of a new technology. There is concern that now some development programs, either within the company or with different partners, might be put aside or altered. People wanted to know how these would go on in the future."

The first two presenters elaborated on this concern by outlining the role of technology in developing the reserves on the Norwegian Continental Shelf (NCS) and the dangers of scaling back future technology development programs. Roy Ruså, Vice President of Technology for Petoro, discussed upcoming technology challenges for operators and service providers in his talk "Technology Critical—Do We Act Accordingly?" Ruså pointed out that the mature NCS province still has many significant business opportunities, but they are linked to even greater technical challenges, such as realizing remaining reserves from smaller prospects, reducing nonrecoverable reserves, and finding and developing new recoverable resources. He acknowledged StatoilHydro as the major driver of technology development on the NCS, but added that the company must continue making significant investments in R&D and increasingly diversify its portfolio of production solutions by pulling in more technologies from other industries and geographic regions.
Technology Focus: EOR Performance and Modeling (January 2009)
Authors: Bai Baojun
Published: February 2015

Technology Focus

Enhanced-oil-recovery (EOR) technologies have drawn increased interested because of the decreasing number of new-field discoveries, increasing number of maturing fields worldwide, and higher oil price, with the oil price peaking above USD 145/bbl in July 2008. It is more important than ever to understand lessons learned from past EOR applications and to develop new technologies and methods. More than 200 papers on EOR were presented at various SPE conferences in 2008. The EOR feature is split this year: EOR Performance and Modeling herein and EOR Operations in June. I categorized EOR papers for this feature into the following seven technologies.Wettability-alteration methods: surfactant imbibition for carbonate reservoirs, low-salinity waterflooding for sandstone reservoirs, and "smart water" for carbonate reservoirs.Chemical-flooding methods for conventional light oil: polymer flooding, polymer/surfactant flooding, alkaline/surfactant/polymer flooding, and surfactant-micelle flooding.EOR methods for heavy oil: steamflooding, in-situ combustion, steam-assisted gravity drainage, surfactant-alternating-gas, gas-assisted gravity drainage, thermal-assisted/gas-assisted gravity drainage, and alkaline/surfactant/polymer and alkali/surfactant flooding.Gas injection and CO2 sequestration: CO2 miscible and immiscible flooding, water-alternating-gas injection, and CO2 EOR and sequestration.Conformance control: gel treatments and foam flooding.Diagnosis and evaluation of EOR applications: seismic method, tracer injection, and mathematical modeling for reservoir heterogeneity and for induced fractures caused by water injection.Other EOR methods: in-situ seismic stimulation, microbial EOR, electrical EOR for heavy oil, and others.

The papers that I selected for this feature fall into the first four categories.

EOR Performance and Modeling additional reading available at the SPE eLibrary: www.spe.org

SPE 113304 • "Analysis of the Wettability-Alteration Process During Seawater Imbibition Into Preferentially Oil-Wet Chalk Cores" by L. Yu, University of Stavanger, et al.

SPE 113417 • "Residual-Oil Saturation from Polymer Floods: Laboratory Measurements and Theoretical Interpretation" by Chun Huh, SPE, University of Texas at Austin, et al.

SPE 113985 • "Evaluation of Manson Lease Oil Field for Improved-Oil-Recovery Process" by J.S. Tsau, University of Kansas, et al.

SPE 117607 • "Experimental Analysis of CO2-Sequestration Efficiency During Oil Recovery in Naturally Fractured Reservoirs" by J.J. Trivedi, University of Alberta, et al.

SPE 111403 • "EOR Methods To Enhance Gas/Oil Gravity Drainage" by P.M. Boerrigter, Shell, et al.

SPE 115204 • "Dynamic Induced Fractures in Waterfloods and EOR" by P.J. van den Hoek, Shell, et al.
Technology Focus: Well Control (January 2009)
Authors: Barnett David
Published: February 2015

Technology Focus

In the last 6 years, the rig count has more than doubled from approximately 1,600 rigs in 2002 to more than 3,500 rigs operating worldwide in 2008. This phenomenal growth has been supported by increasing oil prices that have gone from less than USD 20/bbl in January 2002 to almost USD 146/bbl in July 2008 before falling off drastically in the following weeks. Assuming normal staffing and crew-rotation requirements, more than 30,000 people were needed to operate the 1,900 rigs that were added to the fleet during this period. Experienced personnel are spread thin as new hires are brought onboard to staff the rigs. This influx of new personnel into the industry created the additional burden of needing to train the new hires in the fundamentals of well control. It also makes it necessary to train an increasing number of personnel at the supervisory level as they advance to fill new positions.

Most people agree that the rig crew is the first line of defense against well-control problems. They are the "boots on the ground" that are charged with recognizing the first signs of impending trouble.

On the other end of the spectrum is the increasing number of operator and service-company personnel who are focused on advancing basic well-control principles to accommodate deeper, higher-temperature wells by use of exotic oil-based drilling fluids and by use of various methods of managed-pressure drilling.

The advanced well-control theories are supported by increasingly sophisticated computer models that account for numerous physical changes that become significant only at the elevated pressures and temperatures and increasing depths associated with these extraordinary wells. Interestingly enough, advanced well-control modeling is finding an increased number of uses in less-extreme wells and actually is assisting with teaching the fundamentals that apply to the broader class of wells.

The monumental tasks of training new personnel, training more personnel to higher levels of competency, and developing models to handle the extraordinary drilling environments accurately are all being met with surprisingly good results.

Developments in well-control modeling are providing useful insight into actual downhole conditions and fluid behavior that enables making much better decisions—both in planning and in actual well-control events.

Well Control additional reading available at the SPE eLibrary: www.spe.org

SPE 112761 • "Simulations Comparing Different Initial Responses to Kicks Taken During Managed-Pressure Drilling" by Asis K. Das, SPE, Blade Energy Partners, et al.

SPE 115019 • "Validation of Blowout-Rate Calculations for Subsea Wells" by P. Oudeman, SPE, Shell

SPE 113842 • "RFID Actuation of Self-Powered Downhole Tools" by P.M. Snider, SPE, Marathon Oil Company, et al.
Technology: The Silver Bullet for Production Decline?
Authors: Ferguson Stuart
Published: February 2015

Guest editorial - No abstract available.
Drilling Technology: Monodiameter Drilling Liner - From Concept to Reality
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE/IADC 79790, "Monodiameter Drilling Liner - From Concept to Reality," by Don Campo, SPE, Charlie Williams, SPE, and Andrei Filippov, SPE, Shell E&P, and Lance Cook, SPE, David Brisco, SPE, Bill Dean, and Lev Ring, SPE (now with Weatherford), Enventure Global Technology LLC, prepared for the 2003 SPE/IADC Drilling Conference, Amsterdam, 19-21 February.
Offshore Facilities Construction and Design: Canyon Express Flowline System: Design and Installation
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 15096, "Canyon Express Flowline System: Design and Installation," by Thierry Boscals de Reals and Herve Lomenech, Total; Andre C. Nogueira and John P. Stearns, INTEC Engineering; and Luigi Ferroni, Saipem Inc., prepared for the 2003 Offshore Technology Conference, Houston, 5-8 May.
Well Testing: Effect of Scaleup and Aggregation on the Analysis of Interference Tests
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 84291, "Effect of Scaleup and Aggregation on the Analysis of Interference Tests," by Rajagopal Raghavan, SPE, and Ralph R. Roesler, SPE, ConocoPhillips, and O. Inanc Tureyen, SPE, Stanford U., prepared for the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October.
Shared Vision (February 2005)
Authors: Paccaloni Giovanni
Published: February 2015

SPE produces a number of publications, including magazines such as JPT and several peer-reviewed journals. Starting this month, a new magazine is added to the list—The Way Ahead. This magazine is being written by young SPE professionals mainly for the young segment of our membership (roughly 20,000 students and young professionals), but should certainly be of interest to other sectors (educators, managers, etc.) and to senior professionals willing to listen to the voices of their younger colleagues.

During my many visits with top executives of E&P companies worldwide, the subjects of young professionals and the future of the energy industry frequently arise. How do we keep young professionals motivated? How do we retain newly hired talents? What can SPE do to help the industry train and develop the young, both personally and professionally?

It is not new to our readers that I see the role of young professionals as absolutely central to our industry’s vitality. They are the bridge between students and senior professionals, representing the real key to the future of our industry. Since we all see this future as extremely complex and challenging, we need to do our best to provide all the possible support to this crucial category of individuals today. If we do not, we might face irreversible problems tomorrow. This is why the SPE Board recently approved the launch of The Way Ahead, and supports other young-professional initiatives.

Among the new young-professional initiatives is the very significant eMentor program. The goals of this program are (1) to increase the value of SPE membership to students and young members within the first 5 years of their careers and (2) to engage more experienced members in SPE and provide them with an avenue to “give back” to their profession. Young professionals would benefit from the contact with a more experienced professional, who could give career advice on the day-to-day issues facing them in the workplace. The eMentor program will use information technology to remove the limitations of physical proximity, thus transcending geographic boundaries and time constraints. SPE is creating a mentor database on SPE.org to match mentors and mentees. Prospective mentors will fill out an application that includes information about their education, experience, areas of expertise, and why they want to be a mentor. This program will be underway within the next few months.

Other programs/initiatives for young professionals include an annual Young E&P Professionals Workshop. The second international workshop for young professionals takes place this month in Scheveningen, The Netherlands, following a successful first meeting last year in Stresa, Italy. This event is poised to become a classic annual appointment for our young professionals, and a true benchmark of quality and creativity. I urge all young champions around the world not to miss the next edition of this extremely rewarding initiative, which cements friendships among worldwide young talents and provides exciting opportunities to learn from others’ new ideas.
Q&A with Tom Cochrane
Authors: Cochrane Tom , Donnelly John
Published: February 2015

Tom Cochrane, SPE, is Executive Vice President of Oil & Gas Operations at Cano Petroleum, an independent producer with properties in the midcontinent region of the U.S. that specializes in increasing production from proven fields using enhanced-recovery methods. Before joining Cano, Cochrane spent more than 15 years as an engineer with ExxonMobil. His expertise includes CO2 and waterflooding, the coordination of injection and production logging, volumetric calculations, and drill well candidate identification. He also has extensive experience in production forecasts and reserves estimates.

Can you explain how the creation of Cano came about?

In my opinion, Cano Petroleum was inevitable. Jeff Johnson, our Chairman and Chief Executive Officer, spent several years pitching lenders and investors on his concept for a company that would focus exclusively on mature basins. It took a couple of years, but he ultimately did find investors who shared the vision of his enhanced-oil-recovery concept. These investors were able to look beyond the short periods of time when the price of oil was low and instead focus on the fundamentals of supply and demand. Jeff was one of the first to see this possibility and build a company based on these fundamentals.

What is Cano’s upstream expertise and its operating philosophy?

Cano has significant upstream expertise. My background includes 16 years of experience in secondary and tertiary recovery, including production and reservoir engineering, field maintenance, and production supervision. Production Coordinator John Lacik has 30 years of oilfield experience, including environmental expertise and extensive knowledge of chemical flooding. Cano also has had the great fortune to find outstanding, experienced production supervisors such as Jayme Wollison and Mike Parrish to take care of our assets. We also work with engineering and geologic consultants who have many decades of experience.

Our operating philosophy is to keep our people safe and uninjured and to protect the environment. We ensure that our decisions about equipment repairs and operating strategies appropriately position Cano to achieve the highest margins possible in the long term.
Cased-Hole Completions Without Perforating Eliminate Risks
Authors: JPT staff _
Published: February 2015

Perforating is a double-edged sword for well completions in unconsolidated formations. Perforations open conduits for hydrocarbon flow from the formation to the wellbore. But the perforating process can cause damage to the formation and result in excessive debris, posing operational risk and impairment to well productivity. As a result of a joint industry project (JIP) formed in 2002, a new technology has been developed and field tested that installs a liner and sand control completion in a single trip while eliminating explosive perforation charges and associated risks.

The Enterprise One-Trip Sand Control/Liner Hanger Completion system was developed by a JIP that included three major operators, a large service provider, and a small technology company. The fact that the technology was taken from concept to successful field-installation readiness in just 22 months illustrates that when operators and service/technology providers are committed to a common goal, technology uptake in the E&P business can proceed quickly.

Perforating Risk Factors

Perforating poses operational risks for operators in unconsolidated formations. Additionally, the perforating process can jeopardize well productivity by reducing the area open to flow and damaging the formation.

Generally, well productivity is directly related to the area of flow through a perforation tunnel. The greater the area of flow, the greater the well productivity. Entry-hole diameter and shot density impact flow area. Perforation debris in the perforation tunnel can block the available flow area, as can fractured and compacted zones and broken pieces of formation. The flow restriction caused by crushed zonal rock can also increase skin values, particularly over the life of the well.
Overview: Drilling Technology (February 2005)
Authors: Dupuis Dominique
Published: February 2015

In the early 1900s, my grandmother ran to a field near the village of Le Bourget (future first Paris Airport) to see the trial of a pioneer aeroplane. Seventy years later, the flight time between Paris and New York was approximately 3 hours 30 minutes on the Concorde. At college, I worked with a slide rule; today, my laptop has many times the computing power of the NASA computer used when Neil Armstrong landed on the moon. Dupuis Such revolutions in drilling are not so quantifiable or spectacular; evolution improves the performance continuously. Even during crises, the drilled footage has remained constant. During the last 30 years, the number of bits manufactured has been reduced by a factor of 10, yet we now drill in water depths of 10,000 ft.

Greatest progress is driven mainly by the challenge of the spatial location of a new prospect and the obligation to improve recovery, hence the deepwater extended-reach multilaterals. The new challenge is to reach the deep buried reservoir with vertical depth of approximately 30,000 ft. The borehole pressure, the narrow mud windows, and high temperature trigger new technical development and lead to reconsidering monobore design as the well architecture. The expandable-casing technology is very promising. The second aspect is the change between engineering criteria and a probabilistic approach (for instance, applied to casing design where the probability of a situation or event is rendered acceptable) by improving safety procedures and equipment. This aspect also applies to underbalanced drilling with new procedures and devices.

Highlights of promising evolution include drilling-hydraulics optimization by revisiting classical drillpipe dimension and design to decrease the pressure losses (e.g., use of 4-in. drillpipe with streamline connections in a 6-in. hole); reconsideration of trajectory and drag and torque computations in directional drilling, taking into account drillstring stiff-ness, which could make future models more accurate; and future development of a low-cost 3D rotary-drilling system to improve onshore performance.

We regret that if drilling models improve, there is too little evolution and willingness to acquire drilling-parameter data, the weight on hook is deducted from the tension of the dead line for a difficult assessment of the systematic error caused by line reeving, rendering friction analysis difficult.

Evolution is steady, but has been rather spectacular when you look closely.

Additional Drilling Technology Technical Papers

Available at the SPE eLibrary: www.spe.org

SPE 89959 - The Trouble-Probability Plot: A New Measure of Drilling Maturity

SPE 91583 - Using Rotating Control Devices Safely in Today’s Managed-Pressure and Underbalanced-Drilling Operations

SPE 87217 - Increasing Effective-Fracture Gradients by Managing Wellbore Temperatures

Available at the OTC Library: www.otcnet.org

OTC 16564 - Casing Drilling With Retrievable Drilling Assemblies
Solution for Improved Riser-Tower- Systems Installability and Operability in Deep Water West of Africa
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16630, "Bundle Hybrid Offset Riser: An Advanced Solution for Improved Riser-Tower-Systems Installability and Operability in Deep Water West of Africa," by Giovanni Chiesa, Saibos S.A.S.; Floriano Casola, Saipem S.A.; and Francois Regis Pionetti, Saibos S.A.S., prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.

Several riser-system configurations have been developed to assist hydrocarbon recovery from deepwater reservoirs. Vertical hybrid-riser systems were pro-posed for various deepwater developments west of Africa. The bundle-hybrid-offset-riser (BHOR) concept of a vertical hybrid riser uses bundle arrangements of multiple conduits to enhance flow assurance for delivering the production stream to the surface treatment facilities at production conditions anticipated during the field life. The bundle arrangement includes gas lift capability.

Introduction

Development of hydrocarbon resources in deep and ultradeep waters requires suitable gathering and transportation systems to deliver the production stream to the surface treatment facilities from remote subsea wells. Flow-assurance management becomes more important as reservoir exploitation moves toward deep water. The riser system is critical for flow-assurance management because of the following aspects.

- Significant temperature drop following depressurization along the riser conduits may affect the arrival temperature of the produced fluids at the surface receiving facilities.

- Gas lift injection capability boosts produced fluids to the surface, particularly when the gas content of the produced fluid is low; the gas lift stream must be delivered to the bottom of the riser conduits under certain pressure and flow-rate conditions that minimize the temperature drop along the riser length.

- Production conduits filled with wet gas following shutdown can lead to potential hydrate formation during restart, or produced fluids can enter the gas lift line through the injection orifice, potentially blocking the line in the event of low temperatures.

- Methanol-injection capability can eliminate hydrate on restart.

- Full depressurization of the flowline can dissipate a flowline blockage