bluuebunny/crossref_metadata_2025 huggingface dataset:
Decommissioning Challenges in Thailand
Authors: Tularak Ajj , Ali Khan Waqar , Thungsuntonkhun Witsarut
Published: December 2007

Thailand's oil and gas industry has been successful in finding and recovering hydrocarbon reserves in the Gulf of Thailand since last three decades and have currently installed over 200 fixed offshore structures. Some of these installations are now reaching the end of their economic productive lives and will need to be decommissioned soon. There are complex issues in terms of legislation, environment, safety, costs, technical feasibility and public acceptability. This paper describes the issues relevant to decommissioning in Thailand and proposes appropriate decommissioning solutions developed over the past few years.

The proposed decommissioning solutions are intended to support Thailand's oil and gas industry and its regulators in ensuring compliance with international decommissioning guidelines, balancing economics, safety, practicality and technical feasibility of operations with the environmental benefits and also satisfying needs of the key decommissioning stakeholders in Thailand so as to achieve conflict-free process of decommissioning.

Technical aspects of offshore removal process primarily relates to the lifting of modules and sub-sea structural cutting methods. Lifting techniques range from conventional crane barges used in installation to specialized decommissioning vessels. Basically cost, technical feasibility and safety are major drivers in selection of appropriate lifting method. Sub-sea cutting include explosives and cold cutting techniques, for which cost and environment are the major decision making factors. Environmental aspects of decommissioning can be categorized into short term and long term. Short term environmental impacts are primarily related to the decommissioning methodology whereas the long term environmental impacts are related to the chosen disposal scenario i.e., final destination of each component of an offshore facility. Key recommendations regarding environmental solutions are in the form of Best Practicable Environmental Option (BPEO) framework, which helps determining balanced disposal scenario as well as suitable decommissioning methodology.

Increased energy demands have currently resulted in rapid growth of number of offshore installations in the Gulf of Thailand. At the same time, the old disused installations need to be timely and appropriately decommissioned, which is not possible without having acceptable decommissioning solutions in hand. Such solutions need to be in compliance with applicable international decommissioning guidelines while adopting best practical environmental option hence assuring conflict-free decommissioning process. Therefore, development of such decommissioning solution are significant in assuring "RESPONSIBLE PERFORMANCE: TO DO THE BEST WE CAN" in order to help attain sustainable benefits for further development of Thailand's oil and gas industry.
Petroleum Industry Guidelines for Emission Reductions From Carbon Capture and Geological Storage
Authors: Siveter Robert , Ritter Karin , Cappelen Fredde , Shires Theresa
Published: December 2007

Carbon Capture and Geological Storage (CCS) may play a significant role in mitigating greenhouse gas (GHG) emissions. Oil and natural gas companies are actively pursuing innovative research and new technology initiatives to answer the technical and policy questions surrounding CCS. This paper presents an overview of a recent collaborative effort between the International Petroleum Industry Environmental Conservation Association (IPIECA) and the American Petroleum Institute (API) to develop guidelines for accounting and reporting of GHG emission reductions from CCS projects.1

The focus of the CCS guidelines is on specific technical considerations and the assessment of project emission reductions over the entire CCS chain – capture, transport, injection and storage. The guidelines address potential baseline candidates and scenario assessment, potential emission sources, and monitoring considerations. Case studies for three potential applications are provided to demonstrate the application of emission reduction principles. Key messages include:Growing industry experience with CCS can be used to develop an overall approach to managing geological storage and reducing the risk of unintended physical leakage. Comprehensive examination of possible sites, with appropriate site selection for geological storage, as well as operation and monitoring, are all components of a risk management approach.Good practices in monitoring are especially important for CCS to be a safe and secure GHG emission reduction option.Monitoring should be based on a site-specific risk assessment, with monitoring methods appropriate for the identified risks and to assure the long-term environmental integrity of the storage.

Oil industry experience and expertise provide confidence in CCS as an effective emissions mitigation option. Through these guidelines, API and IPIECA aim to assist the petroleum industry in identifying, assessing, and developing CCS projects with the potential for producing credible GHG emission reductions.
Integrating Environment As A Core Business Value: Perspective on Corporate Social Responsibility
Authors: Avila Randolph A.
Published: December 2007

When we talk about corporate social responsibility, we don’t see it as something we do to society, it is inherent in everything we do. Niall FitzGerald, 2003

Contemporary society expects corporations to be more socially responsible. The notion that a corporation is an economic institution engaged in the production of goods and services with the end-in-view of maximizing shareholder value has been de-emphasized, if not persistently challenged. The prevailing view holds that, as a central part of modern society, corporations are economic institutions with ethical responsibilities to society. The modern corporation is not only concerned about its economic performance and its fiduciary duty to its owners, it is equally concerned with the well being of its employees, the welfare of the community, the health of the environment and many other societal concerns.

If we feel uncomfortable with this idea, it is for the reason that we continue to hold a deep belief in the conventional concept of the corporation which suggests that its raison d’être is purely economic and that the corporation will avoid, where possible, social benefit issues. Revealing some kind of tension between the economic and social categories, the conventional view further holds that business ought to be methodologically differentiated from the other societal institutions engaged in equity concerns and the distribution of social benefits.

The contemporary view holds that social responsibility is integral to the wealth creation process of business. As opposed to differentiation in the former, it presupposes functional unity in that, along with improving economic performance, the modern corporation is also concerned with improving quality of life.
Development and Conservation: Biodiversity Monitoring Within the Camisea Gas Project
Authors: Martinez S. , Soave G. , Mange G. , Ferretti V.
Published: December 2007

The Camisea Gas Project is located in a highly sensitive area, within the Amazon rainforest in the basin of the Lower Urubamba river, eastern Peru. It is not only a biodiversity hotspot, but the homeland of ancient native communities of the Machiguenga ethnic group. Another distinctive feature is the isolation in which the area still remains, given the geographical setting (natural barriers), and the inexistence of roads.

The Project consists of a Gas Plant on the shore of the Urubamaba river, four pads in Block 88 and two pads in Block 56 with directional wells, and around 70 km of flowlines. Initially, a 760 km2 3D seismic survey was performed as well.

A development like this, in such a sensitive area, has the likelihood to produce mayor direct and indirect impacts on biological diversity. To be able to measure these impacts over the Project’s lifetime, a sound biodiversity baseline study is a must, and should be developed as part of the initial Environmental and Social Impact Assessement (ESIA). In adition measurable indicators reporting to different scales (landscape, communities, populations, species, etc.) should be used to identify trends and changes in an early stage as part of the monitoring program, and when possible point out the potential source of affectation.

The Camisea Long Term Biodiversity Monitoring Program (PMB), started its scoping activities in 2002, and undergone a stakeholder engagement and participative process over more than 2 years. Although biodiversity base line research was conducted (at least in part or the total area evaluated) for the ESIA process, the Program formal activities started in 2005, with the implementation of a work plan enriched by the extensive consultation process. Participation was also promoted within the Native Communities, and currently, more than 60 Machiguenga people work for the Program as co-researchers, along with scientists of various Peruvian and international institutions.

To properly feedback the Camisea Project, and incorporate Biodiversity as a Company Corporate Policy, the Management System was modified so as to integrate procedures, training and management plans. A team of specialist from the Company, the Program and the ISO consultant work together on an ongoing process to produce this result.

This paper reports about the experience achieved, the policy established by the company, the process of designing a Long Term Biodiversity Monitoring Program, and the main results obtain up to date.
Application of a Systematic Technique for the Characterization of Naturally Occurring Radioactive Materials (NORM) at Bongkot Field and Songkhla Petroleum Development Support Base
Authors: Limbanyen K. , Soponkanabhorn T. , Chanyotha S. , Chankow N. , Krobbuaban P.
Published: December 2007

PTT Exploration and Production Public Company Limited (PTTEP) strive at all times to ensure that incidents affecting the health and safety of its employees, contractors and members of the public, and the ecological environment shall not occur. The NORM: Radionuclide Analysis Project was initiated in 2003 by the Nuclear Technology Department, Chulalongkorn University, with the cooperation of academic institutions, private enterprises, the Thai government and private service companies, to develop systematic methodologies for characterization of NORM in Thai industry and acquire useful data regarding NORM characteristics throughout the industries for improvement of safety hygiene and environmental standards.

The project has revealed systematic methodologies to determine the concentrations of NORM content in all potential sources and receptors-the "Cradle to Grave" concept.

The NORM characterization project at PTTEP was conducted from 2003 to 2006 by focusing on 3 main areas: 1) PTTEP1 onshore oil production asset, 2) Bongkot offshore gas & condensate production asset, and 3) PTTEP Petroleum Development Support Base, where used equipment and wastes from Bongkot were stored. In this paper, the application of the developed methodologies and results obtained from the long-term and systematic study on NORM characterization of studied areas numbers 2 and 3 above will be presented.
The Business of Environmental Performance
Authors: Marshall Jessica M. , Duong Thomas M. , Serwinowski Mark A. , George Greg R.
Published: December 2007

Everyone is in the business of the environment, from small coffee shops to large oil and gas companies. The capital and social markets are scrutinizing the environmental performance of companies, often using obscure and inconsistent measures, resulting in impacts to reputation and shareholder value. Increasingly, the efficacy of non-governmental organizations, environmental advocacy, investor groups, and public awareness of a company’s lack of performance can create negative impacts. For example, United States shareholder proxy suits are being used by investors at an alarming rate to advocate on a range of issues, such as climate change.1 Therefore, it is crucial for companies to establish clear business measures to assess and drive internal performance and to effectively communicate those performances externally.

Environmental performance is vital to the interests of an organization. The business values from environmental performance include efficiency improvements, cost reduction, and risk management, among others. On a fundamental level, environmental spills and wastes represent inefficiencies to the business resulting from lost products. Moreover, the associated remedial expenditures from spills and releases can represent a significant amount and are escalating, directly impacting the corporate bottom-line. According to a study by the American Petroleum Institute, total environmental capital expenditures within the United States grew at an average of 25% per annum (from $1.87B to $4.67B USD) for the five years prior to 2003.2

This paper explores the assessment and communication of environmental performance in the following areas:Business Integration of environmental activities into commercial and asset planningRisk Management of operational activities by ensuring regulatory compliance and minimizing environmental footprintStakeholder Engagement with key stakeholders, both internal and external, to facilitate transparency and trustRegulatory Development to advocate appropriate and realistic strategies in relation to emerging regulatory policies
Thai Rice College Project, Phase 1-6 [2002 – 2007]
Authors: Klang T. K. , Lumplaimas A. , Burirum C.
Published: December 2007

PTT Exploration and Production Public Company Limited or PTTEP, takes its social responsibility under the conception of "From Underground Asset to Wisdom" in conducting the social and community development programmes.

In collaboration with the Population and Community Development Association, named as PDA, PTTEP has been supporting the farmer’s career development programme in northeastern Thailand since 1996. The target area is Tambon Kok Klang, Amphoe Lumplaimas, Changwat Burirum which comprises of 16 villages, where there is no irrigation system in the area and the rice farming depends only on the seasoning rain water. The farmers can grow rice once a year and the productivity is lower than average, which could not cover the costs of farming in some drought year. This is the very limited condition that makes most of the farmers becoming less opportunity group in the country.

In 1996, PTTEP began with the experimental farming to improve the red jasmine rice breeding in able to resist the rice disease and drought. Meanwhile, with the assistance of the Thai Rice Foundation, we worked together to study the fundamental problems in order to get the proper solutions of problem solving for establishing the objectives of the project.
Transboundary-Oil-Spill Management in the Gulf of Thailand: Industry Participation on Response Arrangements Between Cambodia, Thailand, and Vietnam
Authors: Guevarra J.
Published: December 2007

The Gulf of Thailand (GOT) is a relatively shallow sea bordered by the littoral states of Cambodia, Malaysia1, Thailand and Vietnam. A large spill occurring inside the Gulf would pose a number of problems; chief of this is the response when the spill crosses national boundaries. There is a vital need then for a tripartite agreement between Cambodia, Thailand and Vietnam on oil spill response arrangements if such an event should occur.

At present the three countries have signed a joint communiqué for oil spill management in the Gulf. This is a "soft" document in that it only gives general statements and principles as agreed upon by the countries but not the details on how these could be achieved. A binding "hard" agreement is unlikely in the short term and any oil spill response in the Gulf will have to be handled by each country’s national oil spill contingency plan (NOSCP) independently.

Over the past decades there have been a number of initiatives of littoral states to put in place preventive measures to protect themselves from the threats of marine pollution, including oil pollution. One is the formation of the Tripartite Technical Experts Group (TTEG) on the Safety of Navigation in the Malacca and Singapore Straits by Indonesia, Malaysia and Singapore. Another is also the ASEAN-OSRAP (Oil Spill Response Action Plan). This was set up in 1993 by six ASEAN countries, namely Brunei Darussalam, Indonesia, Malaysia, the Philippines, Thailand and Singapore.

There are a number of other agreements in place in the Asian region on oil spill management. The main problem is the capacity of the developing countries, especially in Southeast Asia, to properly respond to oil spill events, especially large ones. Public-private partnerships between industry and governments may be a way to solve this problem. It has been shown that industry involvement, especially early on, is indeed beneficial and essential.

This paper will focus on the trilateral agreement between Cambodia, Thailand and Vietnam and how industry resources can be tapped early in the process to help in the fulfillment of a unified response plan in the Gulf of Thailand.
The Safety Benefits of Remote Operations Centres
Authors: Lang K. , Cannon K. , Hoedt B. D. , Hanson M.
Published: December 2007

The Safety Benefits of Remote Operations Centres

The rig site is historically an environment that has both a significant range and number of hazards associated with the operations that occur at it, as well as with travel to and from it. To undertake an effective risk avoidance strategy as well as being able to deal with the practical limitations of accommodation at the rig site means that minimization of risk exposure is the ideal approach. The question is whether this is viable or possible.

A remote operations centre has now been developed and used that allows support to rig sites and even some aspects of remote management of operations. While there are always attempts to utilize new technology to reduce the number of people at the rig, this process maintains or even improves the competency available to support such remote operations. Communications infrastructure now allows delivery of this support to multiple rig sites simultaneously and even facilitates remote control of rig site PC’s. Additionally, full time Applications Engineering in the centre improve Drilling Optimisation and Geoscience deliverables on a 24/7 basis 365 days a year.

These centres therefore allow safety benefits as well as efficiencies in resources with several wells being managed at the same time, in addition to providing depths of expertise that hitherto was unimaginable. Although these centres of expertise reduce risk significantly, it was recognized that there remained other hazards that needed to be effectively managed and addressed at the planning stage. These include risks to the centre based staff as well as those that potentially could increase risks at the rig site. This paper seeks to share some of the problems, the hazards and risks as well as the good practices that can be applied in developing such a remote engineering centre.

Using this technology, safe and efficient remote working can be achieved making the concept of the remote operations centre a truly low risk environment.
The Northeast Caspian Sea: Oil Developments in a Sensitive Environment
Authors: Kaltayev Arman , Sokolsky Arkadi
Published: December 2007

Oil development in the Northeast Caspian Sea is challenged by a number of physical and biological environmental factors. Physical factors include complex climatic and hydrologic conditions. Biological factors consist of unique and sensitive ecosystem, and strict environmental regulations, limiting duration of operations and waste disposal options. To address these challenges oil companies have to adopt management practices aimed to minimize environmental impact, mainly concerning waste management, navigation and oil spill response preparation. Studies on sediments and benthos around a number of offshore exploration and appraisal wells showed changes in benthic communities within 50-300 m distance around some of these wells caused by sediment resuspension, petrogenic hydrocarbon run-offs and possible spills of drilling cuttings or drilling mud. These changes were limited, however, in both time and space. To avoid more adverse impact in the future it is suggested that construction and navigation activities should be limited, especially during biologically sensitive seasons, waste management practices and procedures reinforced. Special considerations should be given to rigs and platforms decommissioning.
Capitalizing on Stick-Slip Pseudo-Plasticity of Formation Improves Production of Dual Hydraulic Fracture Completions
Authors: Surjaatmadja Jim B.
Published: December 2007

When placing two planar hydraulic fractures in close proximity, simultaneously, within a formation, two factors immediately come to mind. One is that the two growing hydraulic fractures must share the injected fracturing fluid, and the other is that one hydraulic fracture will tend to resist the opening of the other, making their hydraulic fracture growth almost impossible and leading to an imminent screenout when proppants are introduced. On the other hand, taking advantage of the stress changes caused by a first hydraulic fracture and placing another fracture very soon thereafter can be effective—provided the fracture extension is in a totally different direction and is substantial. Otherwise, the fractures will later compete for producing hydrocarbons from the same area within the reservoir.

Short, narrow hydraulic fractures tend to act in the linear elastic domain of hard-rock formations. Even though such hydraulic fractures cause stress modification in nearby areas, the hydraulic fracture collapses as soon as pressure is released, and modification of stresses will be limited to the displacement from the propped open thickness between the hydraulic fracture faces. The effective hydraulic fracture redirection distance of a later fracture will be small; hence the production improvement contribution of the later fracture will also be small.

This paper describes a hydraulic fracturing stimulation method that capitalizes on the heterogeneous qualities of deposited layers of formation rock, which allows them to slip between weaker micro-layers, thus replicating a weak plastic behavior of the rock deformed by the crack opening during hydraulic fracturing. The method emphasizes the importance of the time factor for maximizing the effects of the pseudoplastic qualities of hard rock for extended distances, and hence maximizing the orthogonal reach of an immediately created second hydraulic fracture for maximum production enhancement.
Geo-engineering and Economic Assessment of a Potential Carbon Capture and Storage Site in Southeast Queensland, Australia
Authors: Cinar Y. , Neal P. R. , Allinson W. G. , Sayers J.
Published: December 2007

This paper presents geo-engineering and economic sensitivity analyses and assessments of the Wunger Ridge flank Carbon Capture and Storage (CCS) site.

A numerical reservoir simulation examines injection rates ranging from 0.5 to 1.5 million tonnes of CO2/year. Primary factors affecting the ability to inject CO2 include permeability, formation fracture gradient, and multiphase flow functions. Secondary factors include the solubility of CO2 in the formation brine, injection well location with respect to the flow barriers/low-permeability aquifers, model geometry including faults, grid size and refinement, and injection well type. Less significant factors include hydrodynamic effects.

The economics are assessed using an internally developed techno-economic model. The model optimises the CO2 injection cost based on geo-engineering data and recent equipment costs. The overall costs depend on the initial costs of CO2 capture and on source-to-sink distances and their associated pipeline costs. Secondary cost variations are highly dependant on fracture gradient, permeability and CO2 injection rates. Depending on the injection characteristics, the specific cost of CO2 avoided is between A$30 and A$44 per tonne.
Safety Training for the Workforce via E-Learning
Authors: Wheeler C. , Charusalaipong P.
Published: December 2007

Oil and Gas Exploration and Production (E & P) work activity has inherent hazards in its nature of operations. Many previous catastrophic incidents have left a mark in the public’s memory. In recent years, younger and inexperienced workers have joined the industry, which has not made it any easier to curve-down the trends of incidents and the related consequences, e.g. personnel injury, fatality, asset damages and environmental impacts.

As an operator in the E & P business, it is our duty to ensure workforce competency, particularly for workers going offshore. Specific Safety Training plays a key role in the delivery of the many mandatory safety topics. But how best to make subject delivery understandable, interesting, efficient and even cost effective?

Traditional Classroom / Safety Trainer techniques have been used over the years but difficulties can be experienced when encouraging (as compared to enforcing) existing staff to attend mandatory refresher training and stimulating the right atmosphere for new hires. It was time to look at different ways to approach the problem.

Various options were considered but the option that appeared most suitable for our needs was E-learning.

The purpose of this document therefore, is to provide a more detailed understanding of the Safety E-learning option, the applications, commercial considerations and problems involved with its implementation.
Combining Testing-by-Difference, Geochemical Fingerprinting, and Data-Driven Models: An Integrated Solution to Production Allocation in a Long Subsea Tieback
Authors: Dolle Norbert , Gelin Francois , Tendo Fidelis , Goh Keat-Choon , Overschee Peter van
Published: December 2007

Well-by-well production allocation in a subsea production cluster is often very challenging without a separate test line. This is recognized in field development plans and can be mitigated by installing subsea and downhole measurement devices, such as downhole gauges and/or flowmeters. Long-term reliability of these devices, however, remains an issue. In the subsea cluster described by this paper, most of the measurement equipment indeed failed or became erroneous within limited timeframe after installation in 2002. As reliable information became scarcer, the uncertainties in the production allocation increased with a direct negative impact on field management.

The solution that was implemented in this Shell UK Limited operated North Sea cluster consists of an integrated application of periodic testing-by-difference and data-driven modelling. Data-driven models have the potential to act as continuous virtual flow meters, relating pressure and temperature changes per well to variations in the well production rates. Data-driven models for real-time monitoring of well-by-well oil and gas production have been widely deployed in the Shell Group in the form of the FieldWare Production Universe (FWPU) application. For these data driven models to be sufficiently accurate, they need to be calibrated with actual production information. In a subsea environment without testing facilities, this information can be derived from testing the wells by-difference and also from short and medium term production data. This paper shows that fairly satisfactory production rate estimates can be obtained with FWPU, even when the subsea tieback to the production and export facilities is more than 50 km long.

Accuracy of the production rates derived from testing-by-difference can be impacted by interference between the wells, especially with a long tieback. Carefully designing and implementing the test and quality checking the derived rates with well flow models can ensure the usefulness of the data. In this paper we will also show that geochemical fingerprinting of fluid samples taken during the test provides valuable information about the quality of the estimates and the behaviour of the fluids in the flowline.

The aim of this paper is not to justify the omission of physical measurement devices or well testing facilities in challenging subsea environments, but to promote the described techniques as valuable additions and possible contingencies.
Ormen Lange Subsea Condition and Leakage Monitoring
Authors: Abrahamsen Jens , Haugen Svein , Bertmand Trond Benny , Lie Gunnar Hannibal
Published: December 2007

With the Ormen Lange development, Norsk Hydros subsea solutions are taking technological developments on the Norwegian continental shelf a significant step ahead. Nothing will be visible on the surface when the enormous gas field comes onstream in 2007. High pressure, large water depth and distant location called for a new way of thinking in many ways. This paper will present the leakage and condition monitoring system developed to ensure safe and pollution free operation of the two templates at 850 meters of water depth. Hydro and Naxys Naval Technology started already back in 2000 the development of a new type of subsea monitoring system based on technology originally developed for naval warefare and surveillance. After successful testing on the subsea processing plant, Troll Pilot in 2001, the system was further developed and qualified. On the Ormen Lange Templates one centrally positioned module containing an array of acoustic sensors monitors the complete 44 × 33-m template. The system provides location and magnitude of any leak, structural vibration or valve malfunction on the template.
A New Method of Evaluating the Productivity Index for Nonlinear Flows
Authors: Aulisia E. , Ibragimov A. , Valkó P. P. , Walton J. R.
Published: December 2007

This paper addresses the effects of non-linear, non-Darcy flows in reservoir on the value of the productivity index. The productivity index (PI) of the well draining a reservoir with no flux on the exterior boundaries is defined as the ratio between the production rate and the pressure drawdown. Experience shows that during the dynamical process of hydrocarbon recovery this ratio stabilizes to some constant value, which, in general, is a non-linear function of both the pressure drawdown and the production rate.

The linear (Darcy) case is well understood, and excellent approximate formulae are available to compute the PI for various well-reservoir geometries. These formulae are generally obtained through a semi-analytical solution of the transient problem. To handle the more realistic non-linear situation, the current practice is to solve first the nonlinear problem many times for different values of production rate, and then to add some ad-hoc corrective parameter(s) in the linear formulae in order to reproduce the non-linear nature of the flow.

Our approach, based on recent progress in the modeling of transient Forchheimer flows, uses partly non-numerical techniques to evaluate the productivity index. It provides, for a wide class of reservoir geometries, an accurate enough approximate algebraic relation between the PI for the nonlinear Darcy-Forchheimer flows and the PI for the Darcy flows.

We show that the solution of the original problem can be obtained by applying direct variational methods, which are computationally less expensive than the grid based techniques. In addition, by using the existing and newly developed approaches in the theory of symmetrization, alternative "non-analytical" algorithms are presented to assist optimal well design, without repeatedly solving numerically the reservoir simulation problem.

The approach will be demonstrated on practical well optimization problems.
Using Field Results To Guide Proppant Selection in the Pinedale Anticline
Authors: Vincent M. C. , Huckabee Paul
Published: December 2007

A field trial was conducted in the Pinedale Anticline of Wyoming to compare well productivity as a function of proppant type and geologic interval. This study compares production from 446 fracture treatments in 30 new wells completed by Shell between September 2001 and September 2004. Great effort was put into the design of the field trial, the collection of data in a systematic method, and careful analyses of the data. Data and analyses from this field trial have been presented in SPE 96559, SPE 100574, and SPE 106151. This current paper summarizes the techniques utilized in each paper to analyze the field results, compares the relative confidence in conclusions reached with each technique, and highlights lessons learned in the process of conducting and evaluating this field trial.

In this field, the authors conclude with greater than 99.9% certainty that production is affected by proppant selection. Even in this extremely tight formation (∼0.002 mD or 2 microdarcies) the fractures remain conductivity-limited, and productivity is greatly influenced by proppant selection. The extremely high level of statistical significance has been achieved by the following:

A sizeable population of wells were completed by a single operator during a short time interval; Drilling, completion, and fracturing stimulation variables were minimized; Proppant types were compared in the same geologic intervals from wells in a small geographic area; Production logs were conducted and analyzed in a systematic fashion, calibrated and corrected to an equivalent logging date; Production data were analyzed with and without normalization to log-derived petrophysical information; Prior to initiation of the trial, 22 geologic subintervals and four separate study areas were defined to investigate subgroups of data in the most homogenous conditions; Statistical analyses were performed on the full dataset, with smaller subgroups of data, and with numerous normalization techniques to determine whether random reservoir variation could account for the results.

The compilation of these results should be of value to those considering a field trial in a complex geologic setting or comparing the results of propped fracture stimulated wells. Optimizing proppant selection has been shown to significantly increase the economic potential of tight gas wells.
Optimal Region Delineation in a Reservoir for Efficient History Matching
Authors: Yadav S. , Heim R. , Bryant S. , Sinha Rohit , May Ed
Published: December 2007

In a large field, history matching is generally performed first at the field level, then at regional level, followed by individual well history matching. This paper presents a novel methodology for delineating multiple reservoir regions for the purpose of efficient history matching.

Ideally the regions in a reservoir should be independent in terms of their effect on the objective function. Otherwise perturbing one variable to improve the match in a particular region may adversely affect the match in other regions. Full independence of regions within a reservoir is not possible unless they are separated by zero permeability streaks or sealing faults. The proposed approach isolates least correlated and most sensitive regions within a reservoir. The least correlation criterion ensures that there is a minimal effect of changing one parameter in one region, to the responses from the other regions. Further, since the regions are least correlated with each other, each region can be history matched independently and simultaneously. The most sensitive criterion increases the effectiveness of history matching.

In order to delineate reservoir regions that can be history matched independently, principal component analysis (PCA) of the Hessian matrix has been done. The Hessian matrix summarizes the sensitivity of the objective function at a given step of the history matching, to permeability at the grid block level. The eigenvectors obtained during the PCA are suitably scaled and appropriate grid block volume cut-offs are defined such that the resultant regions are neither too large (which increases interactions between regions) nor too small (implying ineffective history matching).

The proposed technique has been successfully tested in a fluvial depositional environment. In order to test the robustness of the approach, zero transmissibility faults were deliberately created in the simulation study. The approach could successfully delineate the regions across the faults.
Reservoir Management Aspects of the Rejuvenation of the Forties Field, UKCS
Authors: Vaughan Owen , Jones Richard , Plahn Sheldon
Published: December 2007

When Apache Corporation bought the Forties field in 2003, the field had produced about 2.5 billion barrels of oil from an original oil in place of nearly 5 billion barrels. Historically, cumulative production from some wells had been more than 80 million barrels. By contrast, the remaining drilling targets in 2003 were much smaller, as well as being distributed across the entire field (18 km by 10 km) and reservoir section. In addition, the facilities were nearly 30 years old and designed for fluid rates very different from those current in 2003.

Since 2003, Apache has rejuvenated the field through a combination of facilities improvements, workovers, and drilling new wells. Management of the Forties reservoir during this rejuvenation has had to take into account the challenges of accessing small, widely distributed targets and the constraints of facilities projects being run in parallel.

Initially, 4D seismic was used as the main tool to identify drilling locations. This was an appropriate technique to identify the larger targets but became less certain as thinner oil columns and deeper parts of the section were targeted. During this initial phase of drilling a fine-scale reservoir model was constructed and is now used with streamline simulation as a tool to assess targets and optimise the waterflood. The installation of multiphase well testing equipment and a widespread use of electric submersible pumps with permanent downhole gauges have provided new insights into reservoir performance. Sand control techniques have been introduced in order to manage the potential for sand production. Understanding and working with the interdependency of reservoir management, drilling, and facilities has been essential throughout the process.

The combination of 4D seismic and simulation techniques which has guided the rejuvenation of Forties are presented, along with the interactions with facility-related projects.
Maximising ESP Uptime in Forties Field—Introducing Successful Frac Packs to the North Sea
Authors: Norris M. R. , Plahn S. , Lowton D. , Tsangueu B.
Published: December 2007

This paper demonstrates, via a comprehensively described recent case history, the transfer of established completion technology into the North Sea. Further, in performing the process the technique has been successfully extended beyond its normal criteria of application.

Today artificial lift in the Forties Field is provided by a large number of electric submersible pumps (ESPs) lifting from shale inter-bedded sandstone sequences. Overall production is affected by the achieved ESP run-life in a field where sand-face failure is not uncommon. ESP failure in the Forties Delta well FD5-1 was found to be due to pack-off from a high proportion of fine shale/siltstone in addition to formation sand. Although simultaneous fracturing and gravel packing are commonly performed in other hydrocarbon producing regions none had been directed at controlling the mechanism of flowing shales and/or claystones.

The well intervention was designed to protect the ESP from shale or sand grain production and provide minimal impairment to well productivity. Both objectives were achieved by increasing the formation face area for inflow and in so doing physically support the formation face in the first such frac and pack treatment executed in the UK Sector of the North Sea. ESP protection was achieved and subsequent well productivity was show to be minimally affected by the presence of the gravel pack.

This case history describes the formation failure mechanism; the detailed corrective well intervention and the resulting well productivity in bring well FD5-1 successfully back into full production up-time.
The Influence of Viscoelasticity on Displacement Efficiency—From Micro- to Macroscale
Authors: Wang D. , Wang G. , Wu W. , Xia H. , Yin H.
Published: December 2007

The displacement efficiency (De) in porous media is usually analyzed by the ratio of the macro pressure gradient driving force and interfacial tension (IFT) between the driving fluid and residual oil. However, when the pressure gradient is constant, macro forces cannot explain the increase in De by driving fluids with elastic properties. Therefore, the change of micro forces acting on residual oil between driving fluids with and without elastic properties is analyzed.

This paper shows the influence of viscoelasticity on De; the difference in the stress of non elastic fluids and fluids with elastic properties when flowing is analyzed; the effect of this stress difference on the micro flow lines in pores is mathematically simulated; the affect of the changes in micro forces caused by the change in micro flow lines on residual oil is shown; this enhanced micro force (without changing the macro pressure gradient) mainly acts on the protruding portion of different types of residual oil in pore(s), causing the protruding portion to change shape and move (mobilize); results on visualization core models confirm the above calculation and analysis; the displacement results on cores by fluids with different elastic properties in the lab are shown; the results of considering the phenomena that elasticity increases the De in numerical simulation are shown and compared with field results; large scale field results on polymer flooding and pressure coring are also shown.

The above mathematical simulation, analysis, lab tests and field results all show that the micro forces acting on residual oil is different when the elastic properties of the displacing fluid varies, resulting in an increase in De for viscoelastic displacing fluids at constant pressure gradient conditions.

This method of micro flow line and force analysis and its conclusions should be useful to further understand the mechanism of De in porous media; should be useful in designing, screening and developing better chemical flooding products, methods and projects to further increase oil recovery; should be useful in the analysis of phenomena associated with injecting non Newtonian fluids and gels.
Artificial-Intelligence Technology Predicts Relative Permeability of Giant Carbonate Reservoirs
Authors: Al-Fattah Saud M.
Published: December 2007

Determination of relative permeability data is required for almost all calculations of fluid flow in petroleum reservoirs. Water-oil relative permeability data play important roles in characterizing the simultaneous two-phase flow in porous rocks and predicting the performance of immiscible displacement processes in oil reservoirs. They are used, among other applications, for determining fluid distributions and residual saturations, predicting future reservoir performance, and estimating ultimate recovery. Undoubtedly, these data are considered probably the most valuable information required in reservoir simulation studies. Estimates of relative permeability are generally obtained from laboratory experiments with reservoir core samples. Because the laboratory measurement of relative permeability is rather delicate, expensive and time consuming, empirical correlations are usually used to predict relative permeability data, or to estimate them in the absence of experimental data. However, developing empirical correlations for obtaining accurate estimates of relative permeability data showed limited success and proved difficult especially for carbonate reservoir rocks.

Artificial neural network (ANN) technology has proved successful and useful in solving complex structured and nonlinear problems. This paper presents a new modeling technology to predict accurately water-oil relative permeability using ANN. The ANN models of relative permeability were developed using experimental data from waterflood core tests samples collected from carbonate reservoirs of giant Saudi Arabian oil fields. Three groups of data sets were used for training, verification, and testing the ANN models. Analysis of results of the testing data set show excellent agreement with the experimental data of relative permeability. In addition, error analyses show that the ANN models developed in this study outperform all published correlations.

The benefits of this work include meeting the increased demand for conducting special core analysis, optimizing the number of laboratory measurements, integrating into reservoir simulation and reservoir management studies, and providing significant cost savings on extensive lab work and substantial required time.
Meeting the Challenges in Alkaline Surfactant Pilot Project Implementation at Angsi Field, Offshore Malaysia
Authors: Othman Mohamad , Chong Mizan Omar , Sai Rithauddin M. , Zainal Suzalina , Zakaria M. Sukri , Yaacob Aisha Ashikin
Published: December 2007

The Angsi field in the offshore Terengganu, Malaysia was identified as the candidate for the pilot project to evaluate the effectiveness of the Alkaline Surfactant (AS) process in improving oil ultimate recovery through the reduction of residual oil saturation. The pilot project entails the injection of AS chemical into Angsi I-68 reservoir and will use a Single Well Tracer Test (SWCT) to determine the residual oil saturation in water-flooded area. This is the first chemical Enhanced Oil Recovery (EOR) pilot project in Malaysia and the results are crucial to support the decision making for a future full field and AS technology implementation in Malaysia.

High reservoir temperature and high water salinity pushes the technical limit of AS application that adds complexity to the pilot design. The implementation of the pilot project in the offshore environment, on an unmanned satellite platform with limited space and facilities provide additional operational challenges to the project team. In addition, the utilization of new and volatile chemicals during the pilot requires an introduction of various field procedures to ensure the operation is carried out in a safe manner.

The paper showcases, the key challenges in the planning and execution of the first offshore AS pilot project in the region. This challenging task demands the multi-disciplinary team to work together to develop the project execution plan with attention to detail during pilot design, planning and operation. As a result, critical parameters such as: treatment sequence, field procedures, equipment requirements and layout, and logistics were considered. The pilot design and procedures that are crucial for a successful pilot operation were developed within the constraints imposed by the offshore environment.