bluuebunny/crossref_metadata_2025 huggingface dataset:
Aging and Life Extension: KP4 Inspection Program - The First Year
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145518, ’KP4: Aging and Life-Extension Inspection Program - The First Year,’ by Alexander Stacey, UK Health and Safety Executive, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.

With a significant proportion of the UK’s offshore infrastructure having exceeded the original design life, the aging population of offshore installations presents a growing challenge to safety. Aging is characterized by deterioration that, in the severe operational environment offshore, can have serious asset-integrity consequences if not managed properly. The UK Health and Safety Executive (HSE) Aging and Life Extension Inspection Programme, also known as Key Programme 4 (KP4), was launched in July 2010 to the UK offshore industry.

Introduction

The purpose of KP4 is to

Determine whether the risks to asset integrity, which are associated with aging and life extension, are being controlled effectively.

Raise awareness of the need for specific consideration of aging issues as a distinct activity within the asset-integrity-management process and of the need for senior management to demonstrate leadership on this matter.

Identify shortcomings in duty-holder practices in the management of aging and life extension, and enforce an appropriate program of remedial action.

Work with the offshore industry to develop a “best-practice” common approach to the management of aging installations and life extension.

More than 50% of offshore installations in the UK sector of the North Sea have exceeded the original design life, typically specified as 20 or 25 years, and this proportion is increasing steadily with time. The majority of installations are likely to remain operational for many years, and, thus, the aging offshore infrastructure presents a growing challenge, particularly as reserves decline and the nature of companies in the market changes. In the extreme case, failure could cause the total loss of an installation with little chance of survival. Thus, the management of aging and life extension must be an integral part of the asset-integrity-management system (AIMS) to ensure continued safe performance.

Integrity management of aging installations and successful implementation of an asset-integrity-management plan for life extension depend on understanding the degradation processes, on accurate knowledge of both the condition of the asset and its response in the aged condition, and on an implementation strategy to deal with the increasing risk of failure with time, which enables the greater likelihood of deterioration to be predicted, detected, and assessed. Risk-based goal-setting regulations, supporting guidance, industry standards, risk assessments, and performance standards provide the basis on which owner/operator policies can be developed.
Disconnect Tools Ease Removal of Upper Completion
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

Intelligent completion systems have the ability to monitor and optimize reservoir performance in real time without mechanical intervention. Although such systems were introduced more than 15 years ago, the industry has only just begun to recognize and accept the numerous benefits derived from their implementation. Operators and service companies are now looking at new applications for intelligent completion technology including:

extended reach horizontal wells

marginally economic assets in which electric submersible pumps (ESPs) are required

regulatory compliance, such as nonfunctional subsurface safety valves replacements

However, these applications bring with them certain challenges. In ESP applications, ESP pumps require periodic retrieval for maintenance. With the high torque and drag in long horizontal wells, deploying intelligent completions on production tubing can become a challenge. When a workover is required to replace a nonfunctional subsurface safety valve, it can become more economical to leave the existing intelligent completion in place, and pull and replace only the upper tubing string including the subsurface safety valve.

How then can one reliably install intelligent completions in these applications? Intelligent completion disconnect tools help address these challenges.

Intelligent Completion Disconnect Tools

Recently introduced disconnect tools for intelligent completion applications by Halliburton facilitate the removal of the upper completion from the lower completion without any destructive or mechanical intervention. This leaves the intelligent completion lower assemblies, such as packers, interval control valves (ICVs), and permanent downhole gauges in the wellbore undisturbed.

Intelligent completions require hydraulic and electrical umbilicals to monitor and control the gauges and ICVs in the wellbore. Besides providing tubing-to-annulus integrity, disconnect tools must also reliably disconnect (demate) and reconnect (wet mate) the umbilicals without affecting the functionality of the downhole intelligent completion equipment. Two variants of the disconnect tool are the hydraulic and the electro-hydraulic. The electro-hydraulic provides the ability to multi drop gauges on a single I-wire and hydraulically actuate ICVs in the lower intelligent completion.

Design

These disconnect tools are exclusively designed for intelligent completion applications. The tool comprises two halves: the receptacle and the disconnect sub (Fig. 1). When the two halves are wet mated, hydraulic and electrical continuity is achieved from the surface down to the ICVs and gauges.
Management System Approach Aims To Meet Human Rights Expectations
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164979, ’Management Systems Approach to Managing Human Rights Issues,’ by Tam Nguyen, Chevron, Bert Fokkema, Shell, Julie Vallat, Total, and Roper Cleland, IPIECA, prepared for the 2013 SPE European HSE Conference and Exhibition, London, 16-18 April. The paper has not been peer reviewed.

A range of external expectations exists for companies to demonstrate how they respect human rights, including having business processes in place to prevent or mitigate human rights issues caused by the company’s projects or operations. The International Petroleum Industry Environmental Conservation Association (IPIECA) has responded to the emergence of external guidelines in connection to implementing human rights due diligence by improving existing management systems and processes.

Background

United Nations Guiding Principles on Business and Human Rights. The United Nations Guiding Principles on Business and Human Rights were developed through an iterative process spanning 6 years and involving extensive stakeholder consultation.

In the first stage of the work, John Ruggie, United Nations special representative to the secretary-general, conducted 3 years of research to develop the global Protect, Respect, and Remedy Framework on business and human rights. Ruggie developed the framework to help clarify the distinct roles of states and businesses in human rights. It rests on three interdependent pillars—the state duty to protect against human rights abuses by third parties through regulation and legislation; the corporate responsibility to respect human rights through due diligence; and the need for citizens to have access to effective remedy, both judicial and nonjudicial.

The United Nations Human Rights Council endorsed the framework in 2008. Upon endorsement, Ruggie established the United Nations Guiding Principles. The principles supplement the framework by outlining how governments should meet their duties and how companies should demonstrate their responsibilities.

IPIECA’s Business and Human Rights Initiative. IPIECA launched a 3-year business and human rights project that leverages the collective experience and practical knowledge of its members. The objectives of the project are to

Support the organizational capability of IPIECA members in two focus areas, company due diligence and community-level grievance mechanisms

Serve as the authoritative reference body for the oil and gas industry on business and human rights issues, including the United Nations Guiding Principles on Business and Human Rights and other relevant external guidelines
Inducing an Earthquake by Injecting Water in a Gas Field
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166430, ’Inducing Earthquake by Injecting Water in a Gas Field: Water- Weakening Effect,’ by Axel-Pierre Bois and Mehrdokht Mohajerani, CurisTec; Niek Dousi, SGS-Horizon; and Stijn Harms, Vermilion Energy, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.

On 26 November 2009, a 2.8-magnitude earthquake (henceforth referred to in this paper as the De Hoeve tremor) occurred in southwestern Friesland in the Netherlands at an approximate depth of 2 km. This relatively shallow depth indicated that the event was induced. The closest mining activities were believed to be in the Weststellingwerf field. A study was required to determine the origin of the tremor, evaluate if it could be followed by other tremors in the future, and estimate its magnitude.

Introduction

The tremor’s epicenter was identified by the KNMI (Koninklijk Nederlands Meteorologisch Instituut: Royal Netherlands Meteorological Institute) (Fig. 1). Three wells are located near the epicenter: Weststellingwerf-01 (WSF-01), Noordwolde-01 (NWD-01), and De Hoeve-01 (DHV-01). They all are producing from formations at a depth of approximately 2 km.

Well WSF-01 was a gas producer between 1998 and 2004; cold-water injection started in 2008 with no tremor reported during the gas-production phase.

Well NWD-01 is immediately outside of the epicenter perimeter. It was producing gas at the time of the event, with no tremor measured before November 2009 and none after.

Well DHV-01 is located in the middle of the estimated epicenter area, but had not been drilled at the time of the event.

The observed tremor, because of its shallow depth, was assumed to be induced instead of having occurred naturally. It was attributed by KNMI to displacements along the Weststellingwerf fault because the seismograms were in agreement with a normal west/eaststriking fault. It was thus necessary to identify which mechanism was at the origin of the fault movement, to investigate whether an earthquake could occur in the future, and to determine the magnitude of the event.

Five mechanisms were studied:

Salt dissolution

Reservoir depletion during gas production

Reservoir repressurization caused by water injection

Temperature variations caused by cold-water injection

Fault weakening caused by lubrication or annihilation of capillary pressure during water injection

However, salt dissolution during water injection was quickly discarded as being at the origin of the tremor because the reservoir intervals do not contain halite. Carbonate dissolution was not pronounced and could not explain fault weakening caused by water injection, either.
Validation of a Biological-Monitoring Design in Highly Diverse Tropical Forests
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165632, ’Validation of a Biological-Monitoring Design in Highly Diverse Tropical Forests,’ by K. Caro, E. Enriquez, E. Juscamayta, E. Oyague, and J. Cabrera, Knight Piesold, and C. Chung, C. Ahumada, A. Watson, and C. Videla, Repsol, prepared for the 2013 SPE Latin American and Caribbean Health, Safety, Social Responsibility, and Environment Conference, Lima, Peru, 26-27 June. The paper has not been peer reviewed.

Biological-monitoring programs provide data for decision making and to ensure the protection of resources. However, in tropical ecosystems that are home to most of the planet’s biodiversity, these programs need to be improved in design and implementation. Block 57 in the Amazon rain forest of southern Peru is an ecosystem with limited information. A systematic biological-monitoring program was designed on the basis of a gradient of disturbance caused by clearing an area.

Introduction

Oil exploration in Block 57 involves clearing small forest areas during installation of drilling platforms. One of the consequences of this clearing is an increase of edges and the presence of habitats with early successional stages. An edge is defined as a transition zone between two adjacent ecosystems or vegetation communities. In these edges, deleterious effects may be generated.

A biological-monitoring plan has been designed as part of an environmental- management plan to understand the effect that the changes in the habitat associated with the exploratory wells within the primary cloud forests have on the abundance, richness, and diversity of the local flora and fauna.

Study Area

Block 57 is on the southern Amazon plain and the first foothills of the eastern slope of the Peruvian tropical Andes Mountains (Fig. 1). This is one of the areas with the greatest precipitation and highest temperatures and relative humidity in Peru. At several locations, total annual precipitation exceeds 3000 mm. Relative humidity exceeds 90% in the mornings, and temperatures commonly exceed 37°C in the afternoons during the dry season when the sky is clear.

The study area is in the buffer zones of the Otishi National Park and the Ashaninka and Machiguenga Community Reserves. It is predominantly hilly, with mountainous areas in the western sector and terrace areas near the Tambo and Urubamba rivers. Floral composition in the study area is very heterogeneous with different densities. Palm trees are another representative and varied group in these forests, sometimes rising above the canopy.

The work design includes three platforms in Block 57—Kinteroni BX, Mapi LX, and Mashira GX. This study includes the results of monitoring conducted on the surroundings of the Kinteroni BX exploration platform, also known as Sagari (Fig. 2).
Interview with 2005 SPE President Giovanni Paccaloni
Authors: Paccaloni Giovanni
Published: February 2015

President's interview - No abstract available.
Building Corporate Reputation To Meet Industry Goals
Authors: Cober Andrew
Published: February 2015

Management - No abstract available.
Overview: Field Development (September 2004)
Authors: Pascolini Osvaldo
Published: February 2015

Overview - No abstract available.
North Caspian Project: Challenges and Successes
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 86685, "North Caspian Project: Challenges and Successes," by Lyazzat Sarybekova, Agip Kazakhstan North Caspian Operating Co. N.V., prepared for the 2004 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Calgary, 29-31 March.
Aquifer Gas-Injection Alternative for Handling Associated Gas Produced From Deepwater Fields
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 16254, "Aquifer Gas Injection Offers an Alternative for Handling Associated Gas Produced From Deepwater Fields," by Yanlin Qian, SPE, Robert A. Wattenbarger, SPE, and Stuart L. Scott, SPE, Texas A&M U., prepared for the 2004 Offshore Technology Conference, Houston, 3-6 May.
Overview: Completions Today (September 2005)
Authors: Gomersall Sam
Published: February 2015

High oil prices are good for the industry. Producers start to focus on value instead of cost. When they do this, the service and supply sector is better able to help by starting to understand the technical and business challenges and creating innovative solutions. These solutions include the development or application of new technologies, creative system solutions, and field-development plans that move the industry forward.

One challenge is ensuring that the service sector experiences benefit from higher oil prices because, increasingly, that is where the expertise, technology, and R&D investment exists. Anything that stifles the growth of the service sector, especially the innovative smaller companies, will become a problem in the future.

However, historically, it usually has been low oil prices that precipitate the most significant changes in our industry. The challenge now is to use the stimulus of high oil prices and value focus to implement new technologies and increase industry collaboration rather than using high oil prices as the cushion to avoid doing anything different.

It is our ability to take significant steps forward when the oil price is high that deter-mines who will be successful and who will not.

There are many reasons for not implementing new technology. At an individual level, they include lack of awareness, lack of expertise, lack of time, and lack of personal stimulus. In the completions area, it is our responsibility to continue to develop and apply new technology, overcoming these barriers and using the high oil price as a driver for change.

The industry is schizophrenic when it comes to collaboration: on the one hand, sometimes we work close together (e.g., joint-venture partnerships), and we share learning through organizations such as SPE; yet on the other hand, both producers and service companies regard knowledge as a differentiator, to be kept away from other companies. The future success of companies will, I believe, require more collaboration and less isolation. Companies and individuals who are team focused and who collaborate across traditional boundaries will be most successful. So as engineers, look outside your organization, share what you have learned, and learn what others are doing.

Available from the SPE eLibrary: www.spe.org

SPE 92024 - “Milling of Isolation Valve With Wireline-Conveyed Technology,” by Krüger, C., SPE, Welltec, et al.

SPE 92392 - “Unique ‘Through-Tubing’ Completions Maximize Production and Flexibility,” by Johnson, M.O., BP plc, et al.

SPE 93920 - “Performance of Downhole-Separation Technology and Its Relationship to Geologic Conditions,” by Veil, J.A., SPE, Argonne Natl. Laboratory, et al.

Available from the OTC Library: www.otcnet.org

OTC 17113 - “Completion Technology on Troll—Innovation and Simplicity,” by Haaland, A., Norsk Hydro ASA, et al.
Quantifying Petrophysical Uncertainties
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 93125, "Quantifying Petrophysical Uncertainties," by S.J. Adams, SPE, WellEval.com Ltd., prepared for the 2005 Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, 5-7 April.

Typical petrophysical deliverables for volumetric and modeling purposes are net reservoir, porosity, permeability, water saturation, and contact locations. These data usually are provided without quantitative determination of their uncertainties. This paper highlights the use of Monte Carlo simulation to derive uncertainties. The technique works with different interpretation models, which commonly is not done. The largest source of uncertainty in petrophysical interpretation may be the interpretation model itself.

Introduction

Petrophysical evaluations are carried out for many purposes, including operational decision making, volume-in-place estimation, and reservoir modeling. In all cases, the uncertainty in the deliverables of net reservoir, porosity, permeability, water saturation, and contact locations is critical. However, these data usually are provided without quantitative determination of their uncertainties.

Given the many possible interpretation models for all the different petrophysical deliverables, this paper used only the most basic petrophysical deliverable, porosity, to illustrate the relationship between uncertainty and the log-interpretation model selected. Verification of log porosity with an independent measure, such as core porosity, also can provide quantitative uncertainties, allowing comparison with the log-derived uncertainties.
Screening Methodology for Downhole Sand-Control Selection
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88493, "Screening Methodology for Downhole Sand-Control Selection," by Chris Farrow, SPE, Helix RDS, and David Munro and Thomas McCarthy, Woodside Energy Ltd., prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October.

The sand-management strategy for existing Northwest Shelf (NWS) fields offshore Australia involves reactive down-hole sand control in the event sand is produced above acceptable limits. Sand-face completions for new wells consider well and system risks during the life of the development. A screening method was developed to evaluate and rank available sand-control techniques for NWS conditions. Published criteria were used in a systematic manner, allowing a consistent, balanced, and transparent view of benefits and risks across the different system aspects.

Introduction

The NWS gas/condensate fields (North Rankin, Goodwyn, Perseus, and Echo-Yodel) are approximately 135 km offshore from Dampier, Australia. Typically, these fields were developed without downhole sand control or specific topside sand-handling equipment. Considerable benefits have been realized in terms of development costs and production capacity as a result, with minimal sand production observed to date. However, there is uncertainty about future sand production as reservoirs deplete or water breakthrough occurs.

Woodside formed an integrated sand team with the specific aim to protect against the possible effects of sand. The team developed a sand-management strategy as follows.

- Manage current (low) levels of sanding by well management (including best practices for sand monitoring, drawdown, and bean up) and assess topside desanding options.

- Develop a downhole plan for key existing wells. Activate this plan on a reactive basis if sand production becomes a problem.

- Build system robustness against the risk of sand by considering the installation of downhole sand control in new wells.

To support this strategy, a systematic approach to ranking available sand-control options (for both remedial and new-field developments) was developed and applied.
Sand Management on the Lunskoye High-Gas-Rate Platform: Quantitative Risk Assessment
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112099, "Applying Sand-Management Process on the Lunskoye High-Gas-Rate Platform Using Quantitative Risk Assessment," by M.C. Gunningham, SPE, Sakhalin Energy Investment Company; M.A. Addis, SPE, Shell; and J.A. Hother, SPE, Proneta UK, prepared for the 2008 SPE Intelligent Energy Conference and Exhibition, Amsterdam, 25-27 February. The paper has not been peer reviewed.

Quantitative risk assessment (QRA) was applied to sand management in the Lunskoye field to minimize risk of failure while maximizing production, reducing cost, and safeguarding reserves. Lunskoye is a high-rate gas development offshore Sakhalin Island. This work has reduced the project risk exposure significantly, while reducing well-completion costs and safeguarding production in the long term.

Introduction

The Sakhalin Phase-2 development comprises two new offshore platforms, one on the Lunskoye field and the second on the Piltun field. The Phase-2 development also includes changing the existing Astokh platform to a year-round production operation. These platforms will be linked to an oil terminal and a liquefied-natural-gas (LNG) plant 800 km away on the southern edge of Sakhalin Island. More than 90% of the gas for the LNG plant will be supplied by the Lunskoye field (Fig. 1).

The Lunskoye field is in 48 m of water in the Sea of Okhotsk, east of Sakhalin Island. The potential of sand production disrupting gas production and LNG delivery was minimized in the design stage of the project. The full-length paper details a QRA based on the as-built Lunskoye-A facilities and updated well and completion designs. The aim was to reduce residual risks further by identifying and quantifying the critical failure modes and identifying appropriate mitigating measures by use of a systematic rigorous methodology based on sound principles, which is able to provide implementable results.

Completion Design and Predicted Sand Production

This QRA of the Lunskoye-A wells and production facilities focused specifically on failure modes resulting from sand production. Sand production occurs when the reservoir effective stresses exceed the strength of the sandstone, resulting in rock failure and disaggregation, during which sand grains become detached from the sandstone. The effective stress in a reservoir increases during depletion, causing the weaker sandstones to fail, followed by the failure of successively stronger sands as depletion continues. If the disaggregated sand is transported to the facilities in the gas and liquid stream, it will result in erosion of the flowlines and will settle in areas of low flow velocities, leading to plugging. If the sand is not transported out of the wellbore and remains in the well, the completion interval will gradually "sand up" and production will decline, requiring a workover and a cleanout to restore productivity.
Comments: Short-Term Pessimism for Gas
Authors: Donnelly John
Published: February 2015

Editor's column

Chevron's decision last month to put its North American land-based natural gas drilling on hold highlights not only how tough things have become for drillers but also this year's divergence in oil and gas prices. Chevron cited poor demand and said it does not make sense to continue drilling and producing gas at depressed prices. Other operators and service companies also were pessimistic about the outlook for gas drilling for the rest of this year when announcing second quarter earnings.

Gas prices in the US are at about a fourth of their value compared with a year ago. Oil prices have rebounded to half of their highs from last year, but the gas market finds itself hampered by new competing supplies from unconventionals, pipeline constraints, and built-in barriers to trade that oil does not face.

In addition to poor demand caused by the recession, drillers are a victim of their own success. The growth of new unconventional gas-shale resources has created a significant oversupply that has helped beat down gas prices. Shale development has become prolific—at Barnett in Texas, Haynesville in Louisiana, and Marcellus in Pennsylvania, among others. Unconventional gas supplies seem to be gradually displacing conventional gas production in the US, a pattern that could be repeated in many parts of the world. Recently, energy companies in Europe have begun to turn more to unconventionals in light of maturing gas fields and concerns of dependence on Russian gas supplies.

Finding and development costs for unconventional production have fallen, and technology advancements have greatly improved unconventional development prospects. Unconventional gas production has been growing sharply since 1990, even as conventional offshore and onshore gas output has declined. In addition, last year's high gas prices led to stepped up drilling, efforts paying off this year in increased production.

Gas is not as tradable or as "moveable" as oil, which is part of the reason efforts to form a global gas cartel, similar to OPEC, have not gotten far. In the US, there is often a disconnect among new gas supplies, gas demand centers, and pipeline infrastructure or capacity. That makes gas prices regionalized, unlike oil, which limits trade that would naturally follow supply and demand signals.

The increasing efficiency in gas-shale development and the exciting new prospects have encouraged some operators to continue drilling this year, including Chesapeake Energy and Anadarko. Early results from the Marcellus-shale development—it is estimated to contain 3 billion to 6 billion cubic feet of recoverable gas—have led Anadarko to believe that it could be a star in its onshore portfolio.

The short-term outlook for gas prices is not good, despite what oil prices do. Gas-shale producers are likely to keep drilling. And new liquefied natural gas imports, not to mention new promising Canadian production such as Horn River, should only add pressure on gas.
Uncertainty and the Volumetric Equation
Authors: Murtha Jim , Ross Jim
Published: February 2015

Guest editorial

Every few years, the topic of correct inputs for use in the volumetric equation re-emerges. Our first recollection is from the 1997 SPE Hydrocarbon Evaluation and Economics Symposium when a dozen or so attendees remained after a session to discuss a logical flaw in a technical paper. All of those present agreed that they had been doing volumetric estimates incorrectly, due to their choice of distributions, and vowed to correct the situation. More recently, in the spring and summer of 2007, SPE's Reserves and Economics Technical Interest Group had a lively discussion on the same topic that ended without resolution and with extensive misunderstanding, in part because of perceived repetition of arguments. Now with the recent release of new reserves definitions and disclosure rules from the US Securities and Exchange Commission and comparisons with the Petroleum Resources Management System developed by SPE and other organizations, we may see more companies using probabilistic methods to estimate hydrocarbons in place, resources, and reserves, so we believe that it would be useful to reiterate the conclusion of those present at that 1997 meeting in Dallas.

The crux of the issue is: What is the correct mathematical basis for establishing appropriate uncertainty distributions as inputs to a probabilistic analysis of the volumetric equation? More specifically: Should the input distribution for each reservoir parameter be based on eitherThe range of values seen in the well data for that parameter, or,The range of uncertainty in the reservoir average for that parameter?

A Simple Model

For illustrative purposes, consider using the volumetric equation in the form: oil initially in place (OIIP)=7758Ahφ(1−Sw)/Bo. The following discussion would also apply to other forms of the equation, such as using gross rock volume and net-to-gross ratio, for example.

The total area of the reservoir, A, is 1,920 acres and 24 wells have been drilled on the basis of 80 acre spacing. The net pay, h, varies between 11 and 165 ft in the wells drilled to-date (Table 1) and statistical analysis of the net pay in the 24 wells shows that the average (mean) net pay is 81.5 ft. For the full calculation of OIIP, we would also need to consider uncertainties in area, porosity, water saturation, and the oil formation volume factor, but we will focus on net pay here.
Perforating System Enhances Testing and Treatment of Fracture-Stimulated Wells
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 116226, "Next-Generation Perforating System Enhances the Testing and Treatment of Fracture-Stimulated Wells in Canada," by M.R.G. Bell, SPE, GEODynamics, and D.A. Cuthill, SPE, Weatherford, prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21–24 September. The paper has not been peer reviewed.

Ineffective perforations adversely affect the completion of fracture-stimulated wells. If the interval is to be tested before fracturing, a clean connection to the formation is required to obtain meaningful data. Low perforating efficiency and variations in perforation cleanup associated with heterogeneous formations can result in uneven treatment distribution and suboptimal completion. A new charge technology has been deployed in Canada. Specific examples show how the system facilitates prefrac evaluation, fracture initiation, and limited-entry fracture stimulation.

Introduction

Shaped-charge perforators are used to create a flow path between formations of interest and the wellbore in cased and perforated completions. Alternative methods include mechanical penetrators or hydroabrasive-jetting tools. Although quick and simple to deploy, shaped charges still provide an imperfect solution.

As Fig. 1 shows, shaped charges are formed by compressing high-explosive powder within a metal case by use of a conical or parabolic metal liner. When the explosive is detonated, the symmetry of the charge causes the metal liner to collapse along its axis into a narrow focused jet of fast-moving metal particles. When the charge is positioned perpendicular to the wellbore casing, the jet penetrates the casing and the surrounding cement sheath and formation rock. In this displacement mechanism, where the steel, cement, and rock are pushed aside by the jet, the process continues until the speed of the jet falls below some critical velocity and cannot penetrate further. The effectiveness of this perforation tunnel is determined by its geometry and quality.

Tunnel Geometry and Quality.

The distance the tunnel extends into the formation, commonly referred to as the total penetration, is a function of the explosive weight of the shaped charge; the size, weight, and grade of the casing; the prevailing formation strength; and the effective stress acting on the formation at the time of perforating. Effective penetration is the fraction of the total penetration that contributes to inflow or outflow of fluid, and it depends on the amount of compacted debris left in the tunnel after the perforating event. Effective penetration may vary significantly from one perforation to another, and, currently, there is no means of measuring effective penetration in the borehole. The effective penetration determines the effective wellbore radius, an important term in the Darcy radial-inflow equation.
Revitalizing Old-Asset Oil Fields Into Intelligent Fields
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 126067, "Revitalization of Old Asset Oil Fields into I-Fields," by Mohammed N. AI-Khamis, SPE, Konstantin I. Zorbalas, SPE, Hassan M. AI-Matouq, and Saleh M. Almahamed, Saudi Aramco, prepared for the 2009 SPE Saudi Arabia Section Technical Symposium and Exhibition, Al-Khobar, Saudi Arabia, 9–11 May. The paper has not been peer reviewed.

Recent advances in oilfield technologies have led to the emerging development of intelligent fields. Integrating these technologies whether downhole or at the surface, coupled with communication networks and sophisticated simulation and monitoring applications, provided significant advancements in monitoring and control capabilities and in decision-making processes. An overall system upgrade in Saudi Arabia resulted in enhanced field surveillance, which led to higher levels of oil production.

Introduction

The Abu Hadriya, Fadhili, and Khursaniyah (AFK) complex consists of three fields that share a common surface infrastructure for fluid-processing facilities and pipelines. Production from the AFK fields started in the early 1960s, but the fields were shut-in from 1983 to 1990 because of the low demand for oil in the international markets. The early production from all of the producing reservoirs was supported by gravity injection because the facilities did not have power water-injection capability and all produced associated gas was flared because there was no gas-handling facility.

Saudi Aramco has embarked on the development of several fields, including the AFK fields, with an aim to transform the mature and remote fields into state-of-the-art intelligent fields equipped with proper handling facilities for oil, water, and gas. The new AFK project is a twofold plan. The first part called for drilling new wells, both oil producers and water injectors. The newly drilled water-injection wells are part of a planned peripheral water-injection program for pressure maintenance. The second part implements intelligent-field components that will enhance automation as well as the communication net-work between downhole equipment and surface facilities. Construction included a new processing facility to handle 500,000 BOPD of Arabian Light crude blend, a new gas plant to process 1 Bcf/D of sour gas from this and other nearby fields, a water-injection plant with a capacity of 1.1 million BWPD to support reservoir pressure, and a complete infrastructure of flowline networks to interconnect the three fields with the centralized processing facility.
En Route: The Endless Battle for a Positive Industry Image
Authors: Labastie Alain
Published: February 2015

President's column

The oil and gas industry has long had a poor image among the general public, especially in western countries. Today, two events have captured the minds of many people, and we must recognize that they reinforce that poor image: last year’s Macondo disaster in the Gulf of Mexico, and the current controversy about environmental damage (drinking-water contamination) related to shale gas development. What should we do about these perceptions?

First, we have to make ourselves heard and explain the important achievements our industry has made and the significant benefits our industry has provided to mankind:

The oil and gas we are producing is more than fuel for our cars or our aircraft; they are really the fuel for the world economy. The incredible life-style improvement in most countries over the last century was made possible mostly by an abundant supply of energy, especially hydrocarbons.

Our industry creates jobs through the entire world. Today, the development of shale gas is creating jobs in North America; we could see new jobs in Europe in some near future if this activity develops. And these days, jobs are more than welcome in many countries, in the aftermath of financial crisis and surge of unemployment.

Developing domestic resources will help many countries to decrease their trade deficit, which is a significant contribution in this period of debt crisis.

In the past 10 years, mostly through the International Association of Oil & Gas Producers, the industry has developed a reliable and, most importantly, credible system for reporting its environmental performance. And the trends are good for both CO2 emissions (stable even if oil and gas production has increased) and hydrocarbon discharges (decreasing with obviously the exception of 2010 due to Macondo).
Hydraulic Fracturing Technology and Reporting Continue to Evolve
Authors: Schorn Patrick
Published: February 2015

Management

Used commercially since the 1940s, hydraulic fracturing technology has consistently fulfilled its purpose of extending conductive pathways deep into the reservoir and maximizing production of hydrocarbons. Over the years, significant improvements in fracturing technology and technique have been made, and its application has become common. Since the advent of unconventional reservoir development, fracturing operations have increased several times over in terms of numbers of wells fractured, horsepower requirements, and volumes pumped. Today, for projects aimed at commercial exploitation of many unconventional resources, hydraulic fracturing has moved from a desirable option to necessity and, in many cases, the only way to economically produce these plays.

Nevertheless, lately the practice has been called into question. Fracturing has been blamed as the cause for a variety of events that concern the general public—from earthquakes to groundwater pollution—and the service industry has not done enough to address these fears. In part, the flames of public fears have been fanned by a lack of transparency surrounding the composition of frac fluids. Service companies have been reluctant to make this information public because they believe it is part of their competitive edge. Service companies and chemical suppliers spend significant amounts of capital and effort developing high-performance stimulation chemistry and they naturally seek a certain measure of protection for the resulting intellectual property. However, there are ways in which disclosure and transparency can be achieved while addressing industry concerns about intellectual property.

It should be noted that hydraulic fracturing continues to be the safest and most economical method available for developing unconventional hydrocarbons. And even in the midst of current controversy, the process and the technology must continue to improve and the industry benefit from further optimization.

Operators and service companies alike are striving to develop more effective hydraulic fracturing solutions. Their goal is to achieve economic production while using less water, proppant volumes, and horsepower and with fewer trucks in order to reduce emissions. The industry is also highly focused on developing fracturing chemistry with an improved environmental profile. The more successful the initiatives, the more sustainable and internationally transferable these unconventional development practices will become.

Some of the immediate topics being addressed by industry include improvements in well integrity assurance with respect to hydraulic fracturing, water volume requirements, flowback capture and treatment, and reporting and disclosure of the ingredients of the fluid mixtures pumped downhole.
Technology Focus: Completions Today (September 2011)
Authors: Horvat Damir
Published: February 2015

Technology Focus

Reviewing the numerous papers for this feature showed that the primary theme throughout the last 12 months, globally, has been intelligent-completion methodologies. Fine tuning this information, it is further seen that the primary interest was reservoir surveillance, reservoir deliverability, and production optimization.

In line with the latest generation of objectives, the scope of real-time optimization may be focused on three major segments: well-performance-model update, well-performance monitoring, and reservoir monitoring. Latest-generation real-time-optimization systems can calculate a voidage-replacement ratio for a given completion/reservoir and its subsections on the basis of daily surface-allocated production and injection. The system alerts the user about any parameter that is outside defined bounds of a voidage-replacement ratio, providing optimization engineers with an indication of given areas of the completion/reservoir that are under- or overinjected.

Also, in recent years, the upstream petroleum industry has been honing its ability to drill and complete increasingly-longer higher-angle wells along complex well paths. In addition, live-well-deployment systems deploy and retrieve perforating guns without needing to kill the well. Whether using wireline, coiled tubing, or snubbing pipe, these advanced deployment systems perforate multiple, or longer, intervals in one run to reduce rig time and completion cost.

Application of intelligent-well-completion technology has continued to grow within the industry, even in the face of perceived risks associated with installation and longevity of the system. Operating companies may face challenges (e.g., the subsurface may be characterized by a double-plunging anticline structure with a thrust fault along the main axis and multiple flank normal faults dividing the three major reservoirs into five or six main producing areas). Furthermore, each major reservoir may be subdivided vertically into more subreservoirs. Pressure maintenance may be by use of peripheral water injection or produced-gas reinjection.

I am, therefore, pleased that many operating and service companies have started a significant research partnership. The research is aimed at finding and developing new completion methodologies and technologies for enhanced production, with the aim of addressing many of the challenges in the upstream petroleum industry.

Completions Today additional reading available at OnePetro: www.onepetro.org

SPE 141456 • “Best Practices for Multizone Stimulation Using Composite Bridge Plugs” by Douglas J. Lehr, SPE, Baker Hughes, et al.

SPE 138322 • “Frac Sleeves: Is Milling Them Out Worth the Trouble?” by G. Wozniak, EQT Resources

SPE 130219 • “Nonuniform Slotted-Liner Completion, a New Approach To Obtain Uniform Production Profile Along Horizontal Wells” by M. Mohammadsalehi, Iranian Central Oilfields Company, et al.
Offset Bow Centralizers Meet Underreamed Well Challenges
Authors: Boncutiu Marius , Berry Richard
Published: February 2015

Technology Update

Underreamed wells are among the toughest challenges to using a centralizer, a device that keeps the casing or liner in the center of a wellbore. Underreaming, the technique of enlarging of a wellbore beyond its originally drilled size, is a drilling method widely used to increase the openhole size, which may be required for various reasons.

Some well planners believe it is safest to drill unknown shallow formations with a small diameter bit and enlarge the pilot hole if no gas is encountered. Underreaming may also be performed if a small additional amount of annular space is desired, for example, if a liner must be run to protect against surge pressures.

A fundamental problem with under-reamed wells is achieving effective casing centralization in the underreamed section. The job of the centralizer is to center the casing to improve run in hole (RIH), allow easier pipe rotation, and to enable the cement column to circulate freely around the tubular and produce a robust cement seal to ensure zonal isolation.

Mud displacement is vital to achieving a good cement bond. The more central the pipe, the more efficient the mud displacement will be. In deviated and horizontal wells, if the tubular is not centralized, it will lie along the low side of the borehole and make cement circulation and the achievement of a uniform cement sheath difficult.

Poor centralization can also impair the cement bond by causing channeling, which can lead to various live annulus problems. Like any fluid, cement will take the easiest route in the annulus, and this can result in an inadequate seal if the casing or liner is not centralized. In addition, if the annular clearance is restricted in some sections, backpressure may result that requires a much reduced flow rate during cementation to avoid fracturing the formation and thereby losing fluid.

Offset Bow Centralizer

The Uros offset bow centralizer developed by Centek is designed for use in underreamed or washed-out well sections. The device significantly reduces initial insertion forces and drag when running through previously set casing. Once through this compressed stage, the offset bow centralizer will revert to its designed outer diameter in the open hole and thus maximize standoff without additional drag. The device achieves a reduction in drag compared with other centralizers because of its patented bow design, in which the high points of the bows are offset alternately without reducing the strength of the unit or its capacity to centralize the casing in the open hole.