bluuebunny/crossref_metadata_2025_split huggingface dataset:
Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) for Heavy-Oil Recovery: Experimental Analysis of the Mechanism
Authors: Muatasim Al , Bahlani Al , Babadagli Tayfun 
Published: December 2009

AbstractHeavy oil trapped in fractured carbonate reservoirs possesses a great challenge. Previous experience has shown that heating the matrix to drain heavy-oil by gravity is a slow and inefficient process due to low matrix recovery caused by unfavorable matrix properties (oil wetness and low permeability). Acceleration of matrix-fracture interaction by changing matrix and oil properties could be possible, however, by injecting proper hydrocarbon solvent alternately with steam as reported by our earlier work (SPE 117626). This process called Solvent-Over-Steam injection in Fractured Reservoirs (SOS-FR) consists of several cycles, each having three phases: (1) steam/hot water injection, (2) solvent injection, and (3) steam/hot water injection.This paper reports a detailed experimental analysis of this new method. Static and dynamic tests were conducted by exposing (or injecting) heavy-oil saturated fractured rocks into steam/hot water and solvent alternately. Oil-wet sandstone and carbonate samples were saturated with heavy-crude. Different solvents were tested including heptane, kerosene, decane and light crude. In addition to the core experiments, the same procedure was repeated on "Hele-Shaw like" glass models to visually identify the mechanics of the process.Specific observations and conclusions as to how to apply this technique in field conditions, which mechanisms control the rate of recovery and residual matrix oil saturation, ideal solvent type, and optimal operational conditions (optimal soaking time for huff-and-puff and injection rate for continuous injection) were reported. It is hoped the proposed new technique will be an alternative for tapping heavy matrix oil from oil-wet, fractured, deep, carbonate fields.
Transient Multiphase Flow Modeling of Gas Well Liquid Loading
Authors: Veeken Kees , Hu Bin , Schiferli Wouter 
Published: December 2009

Abstract
Gas well liquid loading occurs when gas production becomes insufficient to lift the associated liquids to surface. When that happens gas production first turns intermittent and eventually stops. Hence in depleting gas reservoirs the technical abandonment pressure and ultimate recovery are typically governed by liquid loading. To date, most methods for predicting liquid loading have followed Turner et al. (1969), which describe liquid loading as the point where the liquid droplets suspended in the gas flow start moving downward rather than upward. This paper presents (offshore) liquid loading field data that exceed the Turner predicted values by on average 40%, and analyses the sensitivity of the liquid loading gas rate for different well parameters. It subsequently presents the results of steady state and transient multiphase flow modeling, carried out to identify the influence of the same well parameters. A modified Turner expression is proposed that best fits the liquid loading field data and broadly agrees with the results of a multiphase flow model that uses a modified version of the Gray outflow correlation. The results of transient flow modeling support the flow loop observation that liquid loading occurs due to liquid film flow reversal rather than droplet flow reversal. The impact of these findings on gas well deliquification is explored.
Elgin/Franklin: What Could We Have Done Differently?
Authors: Festa Eric 
Published: December 2009

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

AbstractDetermination 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 (P&lt;sub&gt;ow&lt;/sub&gt;) value is well studied, and many relationships have been developed. Log P&lt;sub&gt;ow&lt;/sub&gt; 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 P&lt;sub&gt;ow&lt;/sub&gt; 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 P&lt;sub&gt;ow&lt;/sub&gt;. This hydrophobic parameter is then correlated to BCF values determined in flow-through experiments, with excellent agreement (R&lt;sup&gt;2&lt;/sup&gt; &#62; 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

Abstract
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

Abstract
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.