bluuebunny/crossref_metadata_2025 huggingface dataset:
Elgin/Franklin: What Could We Have Done Differently?
Authors: Festa Eric
Published: December 2009

At the time of project sanction in 1997, Elgin/Franklin was the largest High-Pressure High-Temperature (HP/HT) development in the world. It required innovation across the full range of operator activities, from fluid modeling, through development concept definition, HP/HT drilling and platform design to commercial framework.

Eight years after production first began, it is fair to say that Elgin/Franklin has not only achieved the aims of the initial project, it has clearly surpassed them. The increased gas export capacity compared to initial design, the successful development of Glenelg (2006) and West Franklin (2007) satellites using extended reach drilling techniques and the recent drilling of an infill well in highly depleted reservoir are some of the key contributors to the success of Elgin/Franklin.

The high level of technical innovation from project conception right through to recent drilling achievements has provided valuable experience, not only for the Total group and Elgin/Franklin partnership, but also for the industry's HP/HT challenges. With hindsight, using this experience, combined with a decade of further progress in technology, some of Elgin/Franklin development features could have been further optimised. This presentation details some of the most significant feedback and provides an insight into the future of Elgin/Franklin as a mature, yet promising asset, which today is at a crossroads for further investments to ensure its continued growth.
The Development of a System to Restore Full Safety Valve Functionality to Wells With Blocked and Damaged Control Line
Authors: Klompsma D. , Lugtmeier B. , Lacy R. , Jacob J.-L. , Jones R.
Published: December 2009

A significant problem confronting Operators in modern field development and production is that created by loss of functionality of the surface controlled subsurface safety valve (SCSSV) due to blockage of, or damage to, the hydraulic control line. The consequent loss of hydraulic pressure to the valve means its closure, the resultant loss of production and the need to provide an alternative safety system in order to continue exploiting the wells reserves Currently two alternatives are available: A full scale workover to pull tubing, replace the inoperable control line and restore functionality to the SCSSV.Installation of a velocity or dome charged subsurface controlled subsurface safety valve (SSCSSV).

The former approach requires a major expense, which may not be justifiable in a mature well, while the reliability offered by the latter approach typically does not meet well integrity requirements and can sometimes lead to reduced production.

Nederlandse Aardolie Maatschappij (NAM) has been faced with this problem in many onshore and offshore wells and was determined to find an alternative solution. Based on the successful completion of a previous development project, NAM asked Weatherford to jointly develop a solution to this problem, which would allow the installation of an alternative control line without the expense of a workover.

In this paper the authors will review the problems associated with loss of control line functionality and consequent SCSSV malfunction. They will go on to describe in detail the joint project which led to the development, testing, and eventual field deployment of the Weatherford Damaged Control Line (WDCL) Safety Valve featuring surface control, which can be installed using wireline and capillary string techniques.
Predicting Reservoir Characteristics From Drilling and Hydrocarbon-Gas Data Using Advanced Computational Mathematics
Authors: Hurst Andrew , Tischler Gerold , Arkalgud Ravi
Published: December 2009

Formation characteristics are predicted using an advanced computational mathematical method and using hydrocarbon-gas and drilling data as input. Robust predictions of porosity and saturation are made in vertical and horizontal wells, in clastic and carbonate reservoirs. The potential of the technology to augment and complement wireline and LWD technology is identified and applications where these conventional data are unavailable are considered.
CO2 Injection Into Depleted Gas Reservoirs
Authors: Galic Hrvoje , Cawley Steve , Bishop Simon , Todman Steve , Gas Frederic
Published: December 2009

The paper presents: the challenges associated with modelling CO2 injection into depleted reservoirs andthe application of Integrated Asset Modelling in planning CO2 injection into depleted reservoirs.

Depleted gas fields represent an opportunity for CO2 storage. However, low reservoir pressure, as advantageous as it may seem, will present a significant challenge for CO2 injection due to CO2 phase behaviour issues. This behaviour will significantly constrain the operating injection parameters during the early stages of CO2 injection.

It has been recognised that an efficient way of understanding and possibly resolving these flow assurance problems is to adopt an Integrated Asset Modelling (IAM) approach. The benefits of this approach are that it recognises the interaction between all the system elements and enables the user to observe the effects of many parameter changes within the whole system.

The PETEX IAM suite of tools was selected to complete this task as follows: PVTP to characterise reservoir fluids and CO2.REVEAL to model the reservoirPROSPER to model well performanceGAP to model the injection systemRESOLVE as an overall controller and integrator.

An integrated asset model was built for CO2 injection into a UK Southern North Sea depleted gas field, allowing various scenarios to be run and providing important data on CO2 injection. This comprised a full field reservoir description and well distribution, injection rates and time frame, trunkline (main CO2 delivery pipeline) and injection hardware requirements, and the impact of external parameters such as seasonal ambient temperature changes etc..

The methodology, workflow, benefits and challenges of this novel approach will be presented in this paper, giving a deeper insight into the CO2 injection planning process.
Integrated Risk Base Contractor Safety Management
Authors: Jatmika Iwan
Published: December 2009

Most oil & gas industries rely on external service providers/contractors to run their businesses. These services range from the very low skilled and low risk to very sophisticated support services with high risks and huge scopes of work (such as turn-key projects). Delivering the contracted work safely is very challenging and depends on how seriously the company manages and monitors its contractors’ implementation of the company's HSE performance expectations. Failure to identify the critical elements of the contracted work's nature of management, its processes, as well as failure to integrate the nature of HSE risks management, will result in un-structured, less sustainable and reactive efforts, rather than an integrated risk-based approach to contractor safety management.

Based on experience, the application of these concepts demands a resource that is experienced in hands-on contracted work management with HSE risk-based management. As we know, the contracted work management includes the following steps:

Plans to contract the work, Assessing the market, Selecting the contractor, Executing the pre-work readiness, Monitoring the work in progress, Evaluating performance as part of lessons learned and continuous improvement.

Monitoring compliance with safety processes and performance requires unique risk-based safety communication and leadership skills. It is critical that both the contract holder management team and its task force team know and comply with the company's safety business processes. This is not always self evident and sometimes can only be identified after a contractor has already been selected, or worse, when a contractor is ready to be mobilized at site. Rectifying it at this stage may already be too late, too expensive, or too difficult. In addition, sometimes a silo HSE performer (contract holder or HSE officer) may address only site occupational safety issues and have less understanding of contracted work safety business processes. This will only serve to compound the HSE communication problems.

In summary, the success of integrated risk-based contractor safety management relies on two critical elements:

persistent monitoring of the risk-based management at every step of the contracted work's business process, the leadership's ability to integrate the language of safety concerns into the contracted work's language of business process elements, such as execution strategies, costs, schedules, engineering and quality management. In fact, contracted work management has their own management language, e.g. turn-key projects, which have very specific management jargon.
The Implementation of a Drilling and Completions Advanced Collaborative Environment—Taking Advantage of Change
Authors: Sawaryn S. J. , Goodwin S. , Deady A. , Critchley C. , Swanson B.
Published: December 2009

Advanced Collaborative Environments (ACEs) were planned as an integral part of the Operator's new Aberdeen office. The move in early 2008 coincided with a major business re-organisation that prompted a critical reassessment of their scope and functionality. The selected approach is well suited to operations in a mature area. During the pilot project, three ACE implementation types were tested. One of these provided dedicated data feeds and visualisation tools within the normal work area, operating only during normal working hours. The others were asset-based onsite, 24/7 and outsourced models, each representing the business model extremes. The selected configuration was closest to the first of these models, with careful provision for future growth.

The results of the pilot studies supported the business case, but suggested that the realisation of many of the benefits would hinge on attitudes, behaviours and working practices. It was concluded that steady growth, based on demand and keeping pace with the changing habits would give the best return. Detailed plans were created for each of the people, process, technology, environment and organisation components of the operator's ACE model. The new building design and layout has greatly enhanced the overall working environment. Other activities included the upgrading of fibre links, the introduction of an operability laboratory to test the compatibility of data feeds and systems, extensive human factor studies, contract re-assessment and the introduction of a dedicated ACE support team. By June 2008, seven rigs were being supported simultaneously, including monitoring the progress of a wired-pipe trial in Trinidad. All this has been achieved during a period of outstanding drilling and completions performance. This measured approach has delivered results, helping to win hearts and minds whilst avoiding over-stretching resources. The paper includes details of the pilot project, implementation and the progress and challenges to date.
Tailored Nanomaterials for E&P
Authors: Genolet Luis , Schmidt Christian , Schmidt Helmut
Published: December 2009

A new nano-material based binder technology has been developed for the improvement of sand consolidation and proppant flow back. The material represents a sol-gel derived nano-composite, the properties of which are defined by the organic as well as by the inorganic components of the composite system. Using this approach, the material was prepared with viscosities tailored between a few to some tens of centipoises for the injection into very low as well as high Darcy formations. For permeability retention, post flushing procedures have been developed, using nitrogen as well as brine or oil. The downhole consolidation process of the binder material is performed by a chemically cross-linking of the organic groups through radical polymerisation. The time period up to the beginning of the curing process of the binder (pumping time) was established by the appropriate choice of the thermal initiator characteristics and its concentration ("curing on command"). The inorganic backbone of the binder material (silicates, reinforced by titania or zirconia, incorporated into the back bone on a molecular level), pre-formed during the synthesis process and accomplished downhole, leads to a very high long term chemical resistance against crude oils and brines, even at high temperatures. The system was tested in a displacement cell at temperatures up to 200 °F and up to 3700 psi. Permeability retention, also in low Darcy formations, was determined to be above 80% after flushing. The strength of the consolidated material depends on the particle size of the treated sand. Using uniaxial compressive strength (UCS) test equipment, the compressive strength was measured up to 1500 psi with fine sands, and 450 psi with coarse sands or proppants. The shelf life time of the system was found to be more than six months as employment testing period, for a thermal initiator-free system. The thermal initiator has to be added just before pumping. For placing the treatment, bull heading as well as coiled tubing can be used. The system has been proved to be a versatile technology, adaptable to different downhole conditions in oil and gas wells.
Method for Determining the Bioconcentration Factor of Linear Alcohol Ethoxylates
Authors: Fraser Greig
Published: December 2009

Determination of the potential of surfactants to bioaccumulate in marine species has long been problematic in the chemical hazard and environmental impact assessments performed for offshore operations. Recently, this issue has become increasingly significant as regulators have invoked the precautionary principle and assume that all surfactants with molecular weight of less than 700 will bioaccumulate, leading to an increased number of oilfield chemical products labeled as environmentally unacceptable.

The relationship between the bioconcentration factor (BCF) of nonsurfactant substances and their corresponding octanol-water partition coefficient (Pow) value is well studied, and many relationships have been developed. Log Pow is generally, therefore, used as a surrogate for the BCF of nonsurfactant substances.

This methodology cannot be applied directly to surfactants because the formal log Pow of such substances is difficult, if not impossible, to determine accurately. By their very nature, surfactants tend to form emulsions or accumulate at interfaces; therefore, the standard OECD 107 or OECD 117 protocols cannot be used.

This paper describes a simple method for accurately determining the bioconcentration factor of linear alcohol ethoxylates (LAEs), an important group of nonionic surfactants that are commonly used in the oil industry. Quantitative Structure-Activity Relationship (QSAR) software built on fragment contributions averaged over a large number of mostly nonsurfactant substances is initially used to calculate a pseudo-log Pow. This hydrophobic parameter is then correlated to BCF values determined in flow-through experiments, with excellent agreement (R2 > 0.99). The method involves no animal testing; is cheap to set up and perform, accessible to all, quick, easy to use and verify; and gives clear output.
Milling of Permanent Bridge Plug Successfully Performed on Wireline
Authors: Stragiotti Stephen , Andersen Øyvind , Karlsen Ole Eddie
Published: December 2009

A technological breakthrough within the application of wireline technology has been achieved. In August 2008, on an offshore platform in the Norwegian Continental Shelf, a wireline tractor and a new wireline milling system were used to mill and remove a permanent bridge plug at 4,147 ft MD.

The operator decided to mill out the plug on electric wireline and worked closely with the service company to develop this novel solution. Having developed and tested several bits and milling tools, results showed that by combining the wireline miller with hydraulically provided weight on bit (WOB), it would be possible to mill out the retaining rings of the plug, which would cause the plug to collapse. The milling control unit allows the WOB to be adjusted for each application and also controls the reactive torque, the force generated when the milling bit engages the plug.

The service company was able to develop the solution within the client's parameters and in accordance with the timeline set out for this project. The offshore operation was completed in three days to the operator's satisfaction.

In another platform well, a permanent bridge plug had been set in 2003 in the sealbore between two screen sections (3 ft sealbore, 67 degree well angle, 4.75" ID). The plug was set in order to isolate the fairly higher watercut in the lower reservoir zone to prolong oil production from the well. In 2006, the well drowned after a two week maintenance period. Two years later, a coiled tubing (CT) gas lift operation was carried out with good results. It was then decided to remove the permanent bridge plug to re-open for production before another CT gaslift operation was carried out. A method for milling the permanent bridge plug was developed based on lessons learned from the other plug milling operation and by extensive testing at the service company's facilities. The operation was successfully completed in 13 days.

This new application for milling completion hardware and other wellbore obstructions offers a cost-efficient alternate technology to existing methods. The success of the milling operation is quite an achievement and has pushed the limits for what is possible on electric wireline.

This paper will examine two cases of milling bridge plugs on electric wireline and the technical challenges that had to be overcome in offshore operations.The first using the well stroker as WOB, the second using the well tractor as WOB.
"Managing a Giant" 50 Years of Groningen Gas
Authors: Dijksman Niels , Steenbrink Joris
Published: December 2009

The Groningen Field is the largest on-shore gas field in North West Europe (100 Tcf). It was discovered in 1959 by well Slochteren-1 and started production in late 1963. The gas is contained in a high quality sandstone reservoir at approximately 2900 meters below the surface. The initial field development took some 15 years during which 29 production locations (clusters) were built and over 300 wells were drilled and completed.

The field development was geared towards the generation of production capacity in order to provide this service for North West Europe. Swing capacity is the ability to accommodate high winter demand in a market which relies on high load-factor domestic production and long-haul imports. In the initial phase of development the production locations were concentrated in the southern part of the field. By doing so, cost of surface facilities and pipelines were kept to a minimum. In the seventies additional clusters were drilled in the central and northern part of the field to equalize the north to south pressure differential. By the late eighties to early nineties, with 50% of the gas resources recovered, the first stage compression project was kicked-off. In total 20 first stage compressors will be installed by 2010.

Over the past fifty years the Groningen Field has been a test bed for Technology. Advancements on seismic processing and interpretation, geological and dynamic modelling, well and tubing design, depletion compressor technology and field automation have greatly improved the ability to manage the field efficiently.

The implementation and planning of future investments on the Groningen Field are underpinned by state-of-the-art geological, dynamic simulation and planning tools supported by an effective Well & Reservoir Management strategy. This enables the generation of an integrated view and results in optimal investment, capacity and volume planning. The integration of data from the field with state of the art modelling allows us to operate the Groningen system as a smart field. On a cold day a handful of operators are needed to produce up to 9Bscf/day.
Discrete Optimization of Oil Production in Thin Oil Rim Reservoir Under Geological Uncertainty
Authors: Hasan A. I. , Ciaurri D. E. , Foss B. A. , Kleppe J.
Published: December 2009

A control system that distributes fluids from an injection to a production well at an adjustable rate has attracted considerable interest in recent years. Several optimization algorithms have been developed for this system and these techniques have proved to be beneficial in reservoir development. In this study, we propose a discrete optimization approach to increase oil production from thin oil rim reservoirs by smart horizontal wells under waterflooding. The smart well was equipped with several on-off control valves that can be adjusted to reach optimum oil production by maximize sweep efficiency and delay water breakthrough. This bring into optimization problem that involves discrete possible choices with valves settings as decision variables. We perform Binary Integer Programming (BIP) in order to decide valves settings in the injection and production well. BIP is one of linear programming problem where variable required being 0 or 1. These variables correspond with on-off control valves. Preliminary results obtained with this methodology show a significant improvement in the oil recovery factor, and the water saturation at breakthrough is observed to be more uniformly distributed across the reservoir, when compared with the reference non-optimized case. In the second stage of this study we add uncertainty in the geological description of the reservoir (permeability distribution), and perform robust optimization. To this end, we consider statistics of the Net Present Value (NPV) in the optimization objective function. We maximize an average of the NPV, and we control the risk attitude by means of a penalty term that involves the standard deviation of that quantity.
A New Methodology to Safely Produce Sand Controlled Wells With Increasing Skin
Authors: Chitale Ashish A. , Stein Michael H. , Arias Brian J. , Narayanan Ram K. , Schott David W.
Published: December 2009

Monitoring Deep Water Gulf of Mexico (DW GoM) wells with gravel-pack and frac-pack completions is an increasingly challenging task. Wells often experience increasing skin, adding to the risk of completion failure. Historically, sand control completions have experienced a 15% rate of sand related completion failures (King 2003). The industry tends to qualitatively evaluate safe target rates as skin increases. Reducing the flow rate based entirely on an increase in global skin can be too conservative and over-restrict target rate. Thus, it is important to know which components of the increase in skin can cause the completion to fail. Furthermore, it is not well understood how to quantify a safe target rate with the increased skin.

This paper will present a new methodology to evaluate the components of skin increase which could cause sand control completions to fail. The failure mechanism we are addressing is perforations plugging by movement of fines and sand. Our new methodology helps quantify the risk and convert it into a safe target rate. This paper will also present case studies of oil and gas wells in the Na Kika Asset, in DW GoM where this methodology was successfully applied.

The well completions are monitored with BP's flux based approach, (Tiffin 2003; Stein, Chitale, et al. 2005; Keck, et al. 2005). In all cases, the wells experienced increased skin, causing the engineers to choke back the well. The analysis showed that some of the skin increase was due to multiphase effects as the reservoir pressure was below the saturation pressure. Accounting for multiphase flow effects resulted in a 30% higher safe operating rate limit than with a conventional analysis. We also determined which skin components likely caused perforations plugging, thereby increasing the completion flux. The results allowed the Na Kika Asset to produce these wells at their maximum allowable safe operating rate with the higher skin, while producing within the BP's flux based guidelines.
Development of Subsea Safety Systems to Allow Well Testing In European Frontier Areas
Authors: Garcia Soule' Virgilio , Mackenzie Colin
Published: December 2009

Offshore well testing operations in the North Sea have, for many years, been confined to the shallow areas of UK and Norwegian continental shelf with water depths ranging from 100 to 1,000ft. Rig selection of these operations has been primarily moored vessels. New discoveries in the Frontier areas have moved the operations into the deep water regions north of Ireland and west of Shetland where water depths range from 2,500 to 10,000ft. The under-explored regions of the Barents and Norwegian Seas also provide extreme weather conditions in addition to a wide range of water depths. The deeper water prospects have moved operators to the use of dynamically positioned vessels. The combination of high frequency and severity weather systems, deep water and the potential of rapid vessel movement create unique challenges for well testing subsea safety systems.

Subsea safety systems (or as often termed subsea landing strings) are critical to maintaining well integrity during any period were there is the potential to flow hydrocarbons. They typically consist of a lubricator valve to allow in-well tool deployment, a subsea test tree to provide dual-barrier well containment and a disconnect function, and a retainer valve to secure test string contents in the event of a disconnect or shear situation.

To ensure all functional goals are achieved in the conditions found in European Frontier regions, several features of available string types need to be taken into consideration. The key features that are desirable in these challenging operating environments are: Rapid disconnect capability through the use of electro-hydraulic controlsDisconnect capability under string tensionUmbilical protection systemMultiple disconnect methodsAt-tree and below-tree chemical injectionValves capable of cutting coil tubing

These features are not commonly available in landing strings provided for the shallower and more benign conditions found elsewhere in Europe. The technologies required can be developed from the experiences from other deep water regions (such as West Africa and Brazil) and the most extreme North Sea conditions
Accelerating the Commercailization of Exploration Success by the Application of Discovery Driven Development Planning
Authors: Hopper C. T.
Published: December 2009

Discovery driven development planning is a process that balances strategic and business drivers with the more conventional technical drivers of subsurface and facilities design to accelerate the transition of an exploration success to a sanctioned project. The conventional approach is to focus on the subsurface interpretation of the reservoir and to plan the appraisal program. However, the next generation of exploration discoveries are smaller and more complex than in the past, so that even after a full appraisal program many of these discoveries may turn out to be commercially sub economic. Applying a simple conventional linear process that progresses from exploration, to appraisal, to option evaluation, to project development will result in a significant number of stranded discoveries. By exploring in the strategic and business arenas in parallel to an appraisal program, commercial solutions can be discovered that will allow these discoveries to progress into sanctioned projects.

This paper describes a discovery driven planning process where commercial opportunities and business solutions are investigated in parallel to the subsurface work program to facilitate a rapid transition from appraisal to project sanction.
The Value of Well Testing—Optimisation of the West Brae Field
Authors: Tharagonnet Mike
Published: December 2009

The purpose of this paper is to increase the data in circulation regarding the value of well testing on established fields. The results of five phases of optimisation, resulting in a 17% increase in field production, following the change out of the multiphase flow meter (MPFM) are presented.

Background on the West Brae field and the uses of the original MPFM will be discussed. The challenges of monitoring and optimising a subsea field without any measurement at a well level, and the benefits associated with well testing are presented. The five phases used to optimise this six producer well system are detailed, along with the economic benefits seen. These economic benefits are compared to the economic case used to justify the replacement of the original MPFM.
Critical Data Needs for Design of Frac-Pack Completions in Today's Oilfield Environment
Authors: Moreno Bernardo , Haydell Garner , Landry Leigh
Published: December 2009

In an unconsolidated environment, operators often employ frac-packs to stimulate the reservoir as well as to provide sand control. If the frac-pack is designed and applied correctly, the stimulation will not only increase the recovery of reserves and reduce drawdown, but the sand control will remain effective for a long period of time. With rig costs presently as high as $600 thousand or more per day, reducing workover needs is a major consideration in today's oilfield environment.

This paper discusses the crucial design requirements for a frac-pack installation and why accurate reservoir data is critical to the effectiveness of both the pumping and completion aspects of the design.

In the past, assumptions on reservoir information for the frac-pack were often based on historical data and conventional fracturing theories because relevant reservoir information was not available. Following these design parameters often provided inconsistent results that did not meet the intended goals, especially in deeper, higher-pressure environments. Moreover, since frac-pack has now become one of the most common methods used in sand-control completions, and development has moved into deeper, more complicated environments, it is even more critical that the essential tools and data required to meet the operator's goals be used in order to design the frac-pack completion.

This paper will discuss the well parameters and other critical information that enables frac-pack completions to be designed to meet today's more critical reservoir, safety, and cost-efficiency needs.
Swellable Packers Provide a Brownfield Water Management Solution in Open and Cased Hole – Case Histories Including Straddles, Plugs, Slimhole Sidetracks and Testing In Corroded Casing
Authors: Al Douseri Khaled M. M. , Barnes Chris , Young Dustin , Smith Peter E.
Published: December 2009

More than two-thirds of the world's oil and gas is currently being produced from mature fields, and although new prospects continue to be discovered, the industry is realizing that the older finds, now mature, are significantly larger than originally thought. Therefore, much of the world's future oil and gas production will continue to depend on brownfield production. Traditionally, when wells in these fields started to show production declines, operators often chose to abandon them rather than consider rework operations, since most production declines resulted from difficult-to-remediate unwanted water or gas production. In addition to water and gas influx, many fields had less-than-ideal production environments that contained CO2 and H2S, causing corrosion of tubulars.

Realization of the need to revisit mature-field production has encouraged new technologies and remedial options to be developed. One of the recently proven technologies, swellable-elastomer packers, has enabled successful workovers, sidetracks, and re-drills that might otherwise have been too difficult, unreliable, or too expensive to be performed a few years ago. The packer uses the swelling properties of rubber in hydrocarbon or water to expand so that the annulus around the pipe is sealed.

This capability has proved to be a great advantage in older wells where corroded, pitted and otherwise irregular surfaces in addition to reduced wall thicknesses due to corrosion make setting and sealing of conventional packers very difficult.

This paper provides case histories and applications of swellable straddles and plugs in openhole and cased-hole scenarios that have enabled shut-in wells to be placed back into production. The discussion will include coiled-tubing tool and wireline deployment methods, wells in which swellable packers have been run as part of the completion string, and testing of swellable packers that provided seals in corroded casing. The principles and techniques involved are applicable to brownfield situations worldwide.
100% Gelled LPG Fracturing Process: An Alternative to Conventional Water-Based Fracturing Techniques
Authors: Tudor Eric H. , Nevison Grant W. , Allen Sean , Pike Blaine
Published: December 2009

A novel hydraulic fracturing process using 100% liquefied petroleum gas (LPG) has demonstrated quick and complete fracture fluid recovery, significant production improvements and dramatically longer effective fracture lengths. The process gels the LPG for efficient fracture creation and proppant transport. With that there is no compromise in the fracture treatment placed when compared to conventional treatments. However, once the fracture treatment is complete and the viscosity of the gelled LPG is broken, the unique properties of LPG create an ideal fluid for complete cleanup. Removal of this fluid from the invaded zone is easily achieved; relative permeability effects, irreducible saturation behaviour and capillary pressure demands are eliminated. Complete recovery of the LPG is consistently demonstrated.

Following conventional hydraulic fracture treatments, effective fracture lengths are frequently observed to be much less than antcipated fracture lengths. This is seen in lower than expected production or evidenced in pressure transient analysis results. A precursor to the poor fracture performance is poor recovery of the fracturing fluid; often less than 50% is recovered during clean-up. In many reservoirs this unrecovered fracturing fluid remains immobile within the formation creating an obstruction to flow. This significantly compromises effective frac length and results in decreased production.

During the fracturing process and subsequent closure of the fracture, the bulk of the fracturing fluid invades the reservoir matrix along the fracture face, referred to as the "invaded zone". This fluid is forced into the reservoir by the significant pressure differential between fracturing pressure and reservoir pressure. Once in the matrix, removal of fluid from the invaded zone can be very difficult as it is held by relative permeability, irreducible saturation, and/or capillary pressure effects.

Fracturing with 100% gelled LPG was first completed in January 2008. By June 2009 over 210 fracture treatments had been completed. This new process has been applied to a wide range of formations from depths of 750 ft through to 11,500 ft. In this paper, short term technical evaluations, such as post fracture pressure transient analysis, are used to demonstrate the rapid cleanup and effective fracture lengths that approach anticipated fracture lengths. Long term actual production comparisons will be a focus on future papers as results become available.
A Proven Methodology to Select and Validate Leading Process Safety Key Performance Indicators (KPIs)
Authors: Herbert Ian
Published: December 2009

This paper provides operators with a methodology for selecting and / or validating the leading Process Safety Key Performance Indicators related to the Plant Design for facilities or platforms.

The importance of Leading Process Safety KPIs is to provide assurance of barriers, also known as Risk Control Systems (RCSs) under HSG 254, ‘Developing process safety indicators’ (HSE, 2006) ahead of any incident. The majority of leading KPI indicators rely on Inspections, Tests and Maintenance to check the functionality of these barriers. However, validating that the design of the barrier is still appropriate is not covered by current leading KPI checks. Operational changes can introduce new requirements and creeping modifications can undermine the expected operations of aging safety barriers.

This paper provides an overview of the use of operational based hazard reviews as a means to identify where there may be design and/or operational failures in the design of safety barriers. Details are presented for the use of Asset Life reviews to determine potential future failures and replacement requirements of safety barriers. Examples of were safety barriers have been identified as insufficient through minor operational changes and potential future major safety barrier replacement issues are shown. This paper focuses on the Plant Design element of HSG 254 ‘Developing process safety indicators’, (HSE, 2006) which currently applies a leading indicator for the percentage of safety critical items of plant or equipment which comply with current design standards or codes, and where this may be undermined because of age and operational changes.
Maximising Recovery From Mature North Sea Assets by the Implementation of Production Optimisation Initiatives
Authors: Akhtar Masud J.
Published: December 2009

Oil was first discovered in the North Sea in the 1970's and some of platforms that were erected during that era are still producing albeit the production has dwindled significantly. With the technical costs on the rise oil & gas operators are constantly on the lookout for cheap and simple solutions. These help not only to increase the hydrocarbon production from a well but also helps in improving the overall field recovery factor. However, sometimes expensive well interventions are necessary in order to better understand the problems faced and then use the data acquired to study and then implement a more long-term/ permanent solution.

The purpose of this paper is to present details on what kind of solutions that have been implemented within the Alwyn field (producing since 1987) in the Northern North Sea. These production enhancement measures relate to a number of different disciplines ranging from topsides modifications to well interventions to sub-surface. As these disciplines originate from different departments within the Company a well performance team was created with the objective of coordinating all production optimisation studies and their implementation on the field.

During the course of this paper more details about the structure of the team would also be provided along with further justification outlining how the team has helped in increasing the production from a number of wells. A large variance in production gain has been observed from these operations dependent on the nature of the intervention this ranged from 50 boe/d to nearly 2,500 boe/d.
Process for Tracking the Evolving Perception of Risk During CO2 Storage Projects
Authors: Polson Debbie , Curtis Andrew , Vivalda Claudia , Saunier Stephanie
Published: December 2009

The paper describes a process for constructing a risk register to be used to track the evolving perception of risk during a CO2 storage project. A project-specific risk register is developed through a structured elicitation process to determine initial perception of risk and through discussion with experts. Regular updating of the register by experts is used to track changes in the assessment of risk as the project progresses and inform decision and actions during the project with the aim of reducing risk to an acceptable level.
Gryphon Field Development—Past, Present and Future
Authors: Templeton Gerhard , Konings Stijn , Wilkie Clare , Benton Paul , Marcas Gabriel , McInally Alan , Ings Rob
Published: December 2009

Gryphon is an early Eocene age field located in block 9/18b and 9/18a-R of the UKCS North Sea. The field has been on production since October 1993 and comprises basin floor high-density turbidite sandstones within the Balder Formation. The thickly bedded Balder turbidite lobes of the Gryphon Field were remobilized during the early Eocene, probably by a catastrophic event such as an earthquake. This resulted in large-scale modification of the original depositional geometries of the sand lobes and the development of seismic scale sand injection wings.

Initial field development was focused on the in-situ massive turbidite lobes. Since August 2004, production started from wells drilled into the injection wings.

Going forward, oil reserves in the Gryphon area will be developed by active oil rim management and drilling of additional development wells.

New development wells can be divided into two distinctive types: massive turbidite lobe targets and progressively more complex injection wing targets. Massive turbidite lobe targets are dynamic targets, generated through reservoir simulation. For this purpose, a completely new dynamic model has been built. Injection wing targets are less affected by existing production and are mainly driven by seismic observations. Given the complex nature of the remaining injection wing targets, technological developments are aimed at improving the seismic data quality.

The new dynamic model also provides a tool to evaluate the resources and the development strategy for the last phase of the Gryphon Field, gas blowdown.

Recent development drilling on the field and recognition of future potential, has allowed further facilities and topsides work to be carried out. This will allow the Gryphon Alpha FPSO to remain on station longer. It is the longest serving permanently moored FPSO in Europe and following the topsides work, the Vessel Class has been extended to early 2013.
Multi-Stage Fracturing of Horizontal Wells Using Ninety-Five Quality Foam Provides Improved Shale Gas Production
Authors: Brannon Harold D. , Kendrick Daniel E. , Luckey Eric , Stipetich Abby
Published: December 2009

The increasingly active exploitation of tight gas shale resources has resulted in new and improved processes to more effectively recover the vast reserves. Horizontal well construction, multi-stage interval isolation, and fracturing techniques are among the more prominent. However, for such otherwise leading-edge engineering and operational processes, ‘minimalistic’ fracturing system technologies such as high rate, large fluid volume, low sand concentration slickwater treatments have been the norm.

The Big Sandy is a productive field of more than 25,000 wells, located in the eastern USA. Production is dominated by ultra-low permeability Berea tight gas sands and Devonian Ohio shales such as the Huron formation. Post-frac commingled production from area wells typically ranges from 20 to 500 Mcf/D. Due to the low reservoir pressures exhibited by the Lower and Upper Huron, they are considered to be fluid sensitive, and consequently, have historically been stimulated with high-velocity nitrogen or nitrogen foam fracturing treatments. Previous studies indicated the long-term production was better in the stimulations including proppant than in those treated with nitrogen alone. Additional studies concluded that clean-up effectiveness was critical to maximizing net present value. Therefore, it was believed that treatments providing proper proppant placement with a minimized amount of liquid loading would be the best route to improving well performance.

Recently, two vertical wells were fractured using a new process incorporating a pre-slurried proppant concentrate foamed to 93-99 quality with nitrogen, and pumped to place ultra-lightweight in partial monolayer concentrations. Cumulative production after the first 30 days was observed to be approximately 200% greater than offsets. Less equipment, tank storage, and water volume are required for the process, providing for a much smaller location footprint, minimal water-hauling expenses, and significantly lower recovered fluid disposal costs.

Following the successes of the process in the vertical wells, several horizontal wells having 8 to 9 intervals each were treated using the new process in the Big Sandy. This paper provides case histories of those horizontal well stimulations, along with comparison to offset wells treated with nitrogen fracs and conventional foam fracs.
Prospectivity on the Erris Ridge (Licence 7/97)—High Risk/High Reward Frontier Exploration on the Irish Atlantic Margin
Authors: Howard A. , Beswetherick S. , Miglio G.
Published: December 2009

Frontier Exploration Licence 7/97 is located 115km offshore north-west Ireland and directly overlies the Erris Ridge. The ridge is an enigmatic, narrow, segmented, NE-SW orientated structural high which lies between the Erris Basin to the east and the Irish Rockall Trough to the west and which, to date, remains un-drilled.

Seismic data quality across the Erris Ridge is typically poor and correlation with the sparse offset well database is challenging. Zones of poor seismic imaging are associated with combinations of complex shallow volcaniclastics, possible intrusive features and large-scale Tertiary channels/entry points which overlie older strike-slip zones and segment the ridge along its length. Displaying considerable complexity and structural variation along strike, seismic based interpretations provide models ranging from a shallow basement horst to preservation of significant thicknesses of Paleozoic and Mesozoic sediments.

Recent work by Eni identifies the potential for prospective section to be preserved on the Erris Ridge resulting in two large prospects, Fiachra and Conn, and a number of leads being identified. The Fiachra Prospect is a large fault assisted four-way dip closure situated within a crestal location on the Erris Ridge and forms the focus of an exploration well planned for 2010. An early Triassic sandstone play (Sherwood Sandstone Group equivalent) is prognosed as the primary reservoir target interval, although several secondary targets also exist.

After an intensive evaluation programme the critical geological risk remains modelling the presence of sedimentary section with reservoir potential in areas where the quality of seismic data is very poor. However, it is concluded that Licence 7/97 possesses good potential for deepwater frontier exploration; the Corrib gas field to the south of the licence area and the Dooish gas discovery to the north indicate the potential for a favourable location within an effective petroleum system.
Siting and Permitting of Class II Brine Disposal Wells Associated With Development of the Marcellus Shale
Authors: Arthur J. Daniel , Dutnell Stephen L. , Cornue David
Published: December 2009

Recent estimates place technical recoverable reserves of natural gas from the Marcellus Shale at approximately 500 tcf. Development is anticipated to consist primarily of long-reach horizontal wells drilled from multi-well pads with each well stimulated using multi-stage slickwater hydraulic fracturing. Currently, it appears likely that disposal via Class II brine water disposal wells will be an important option for managing water produced from Marcellus Shale wells over the long-term. This paper is structured toward brine disposal issues in Appalachia and associated Marcellus Shale development issues. Many issues come into play with both the siting and the permitting of Class II disposal wells in the Appalachians. Currently, the limited number of existing disposal wells in the region along with geologic challenges makes developing new disposal wells a complex process. Well siting of injection wells must address a variety of environmental and access considerations, especially where water will be trucked to the well. Permitting must consider issues such as calculation of the ‘zone of endangering influence", which becomes more complicated in tight or fractured receiving zones. Gaining approval for well testing and other well drilling and completion activities can be different from western or mid-continent states, so upfront planning is critical. This paper will include a review of the regulatory environment in the region, permitting timeframes, regulatory and permitting requirements, formations being considered for brine water disposal and the associated challenges.