bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Acceleration or Additional Recovery? - A Look Back at Three Published Field Trials to Determine the Long Term Benefits of Improved Fracture Treatments
Authors: Blackwood K. , Handren P. , Chapman M. , Palisch T. , Godwin J. 
Published: September 2011

Abstract
There is no doubt that improved frac designs can increase production rates from many reservoirs. However, do these changes merely accelerate recovery, or is incremental production gained by changing the fracture design?
Results from field trials are often published within a year (or even less!) of the initial design changes, and EUR projections are required to forecast the long-term economic impact. This paper will document a re-examination of three tight gas case studies published in the past ten years to determine whether recovery projections were accurate. Included are a review of field studies performed in the East Texas Haynesville Lime, the West Texas Canyon Sand, and the East Texas Cotton Valley-Taylor Sand. The original studies in these tight gas formations were specifically performed to assess the impact of increased fracture conductivity on production. In all cases, the initial analyses documented that increasing conductivity appeared to increase production and recovery.
By revisiting these case studies using extended production data, a more rigorous determination of recovery and associated economics will illustrate whether recoverable reserves are increased from tight gas reservoirs with careful modification of fracture designs. This paper will speculate on the mechanisms that may allow incremental reserves to be captured from some reservoirs, and will evaluate the uncertainty of reserve forecasts constructed from less than one year of production data. This summary should be of interest to any engineer who must estimate the recovery impact of completion changes when only limited production data is available.
Simulation of Two-Phase Flow in Carbon Dioxide Injection Wells
Authors: Pekot Lawrence J. , Petit Pierre , Adushita Yasmin , Saunier Stephanie , De Silva Rohan 
Published: September 2011

Abstract
To model a variety of potential operating conditions in pure carbon dioxide (CO2) injection wells we performed a multiphase transient well flow simulation study. A thermal reservoir simulator was also used to estimate the extent of reservoir cooling and the variation of injectivity index to be expected from injection of cold CO2.
Depleted gas reservoirs are potentially attractive targets for CO2 but their low pore pressure results in low bottomhole injection pressure and potentially two-phase flow regime in the wellbore. Other authors have noted the possible implications of this condition; however, none have addressed the issue using transient flow simulation.
A vertical wellbore model was built in a multi-phase transient flow simulator, assuming representative Southern North Sea conditions. To investigate wellbore profiles of pressure, temperature and CO2 liquid hold-up, parametric as well as thermal reservoir simulations were performed. The latter simulations integrated the bottomhole conditions observed in the wellbore model.
Results show that pure CO2 injected at the wellhead may vaporize or condense as it travels down the tubing, experiencing continuous changes in pressure and temperature as dictated by its change in enthalpy. However, sudden vaporization or condensation is not predicted by the simulator. Two-phase flow cases resulted in stable injection conditions. Well injectivity index varied significantly with injection fluid temperature and pressure, but the extent of reservoir cooling away from the wellbore was limited. This suggests that onerous processing to avoid a two-phase flow regime in CO2 injection wells, such as pre-injection heating or downhole choking may not be necessary at the injection start-up into a depleted gas reservoir.
Offshore Replacement of a Damaged FPSO Fairlead
Authors: McKeown Richard , Bisset Alastair , McKeown Stephen 
Published: September 2011

Abstract
In 2010, the operator completed the successful replacement of a damaged fairlead within the mooring system of its FPSO (Floating Production, Storage and Offloading). This is believed to be the first time that a fairlead has been changed-out in situ on any floating installation in the North Sea. This was a complex operation involving many different vessels and topsides activities. This paper details how the damaged fairlead was safely secured and replaced.
The replaced fairlead was deemed irreparable because one of the axle retaining plates and its associated bolts were missing. However, after further ROV (Remotely Operated Vehicle) inspections, it was discovered that the remaining seven fairleads were also displaying symptoms of the same failure mode i.e. axle retaining bolts were missing or found loose placing further strain on the remaining bolts.
The condition of the axle retaining bolts was deteriorating and the operator was unsure when the next catastrophic failure could occur. Therefore, ROVs were used to secure the seven failreads as effectively as possible by replacing/tightening bolts and air divers were mobilized to install pins to apply additional clamping force while allowing access to the original retaining bolts. The original bolts were replaced and segregated so that they could be analysed onshore.
An investigation was undertaken to understand the failure mode of the FPSO fairleads. It was hoped to compare the differing levels of damage to different factors such as weather, mooring line catenaries, etc… to determine which factors are significant.
It was concluded that the bolt damage was mainly the result of design issues. A combination of QA/QC (quality assurance/quality control) issues, environmental and operating conditions could explain the differing levels of fairlead damage.
The integrity of the mooring system was severely under threat throughout. Plus, replacing a fairlead is a long and costly exercise, therefore early identification of fairlead bolt issues and intervention is extremely valuable.
Experimental Investigation of Near-Miscible Water-Alternating-Gas WAG Injection Performance in Water-wet and Mixed-wet Systems
Authors: Fatemi S. Mobeen , Sohrabi Mehran , Jamiolahmady Mahmoud , Ireland Shaun , Robertson Graeme 
Published: September 2011

Abstract
Laboratory data on WAG injection for non-water-wet systems are very limited especially for near-miscible (very low IFT) gas-oil systems, which represents injection scenarios involving high-pressure hydrocarbon gas and CO2 injection. Simulation of these processes requires thre-phase relative permeability (kr) data. Most of the existing three phase relative permeability correlations have been developed for water-wet conditions. However, majority of oil reservoirs are believed to be mixed-wet and hence, prediction of the performance of WAG injection in these reservoirs is associated with significant uncertainties. Reliable simulation of WAG injection, therefore, requires improved relative permeability and hysteresis models verified with reliable measured data.
In this paper, we, first, report the results of a comprehensive series of coreflood experiments carried out in a core under natural water-wet conditions. These included water injection, gas injection and also WAG injection. Then, to investigate the impact of wettability on the performance of the above injection strategies, the wettability of the same core was changed to mixed-wet (by aging the core in an appropriate crude oil) and a similar set of experiments were performed. WAG experiments under both wettability conditions started with water injection (I) followed by gas injection (D) and this cyclic injection of water and gas was repeated (IDIDID).
The results show that in both the water-wet and mixed-wet cores, the performance of WAG injection is better than water injection and gas injection alone. Changing the rock wettability from water-wet to mixed-wet significantly improve the performance of water injection. Under both wettability conditions (water-wet and mixed-wet), the breakthrough (BT) of the gas during gas injection happens sooner than the BT of water in water injection. Ultimate oil recovery by gas injection is considerably higher than that obtained by water injection in the water-wet system, while in the mixed-wet system gas injection recovered considerably less oil.
Remote Operations—A Remote Possibility, or the Way We Do Things ‘Round Here?
Authors: Cramer Ron , Hofsteenge Hetty , Moroney Tom , Gobel Derek , Akpoghiran Fidelis , Murthy Ajith 
Published: September 2011

Abstract
Shell aspires to maximize unattended operations for all upstream E&P "green" and "brown" field assets using the appropriate level of automation. The benefits associated with down manned operations include the following:
Reducing staff exposure to travel hazards e.g., driving, sailing and flying Reduce staff exposure to process hazards at the well site and drill floor Increased production due to continuous monitoring and optimization by expert staff CAPEX saving due to elimination of unnecessary facilities such as process simplifications and reduced number of offshore beds OPEX savings due reduced travel and reduced logistics Increased staff productivity due to less time spent travelling Reduced GHG emissions as a consequence of reduced travel and improved process efficiency
The underlying premise is that the E&P process should as much as possible be monitored and controlled from a remote monitoring/control room staffed by the most experienced and capable people.
For "green field" facilities the basic design concept that we aspire to is unattended as the norm and attended as an exception that has to be clearly justified.
For "brown fields" we aspire towards as much as possible reducing attendance, again by monitoring and controlling from remote control centers.
This paper will describe the following:
Shell's overall remote operations strategy Technologies associated with remote operations, inclusive of production deferment reducing techniques such as data analytics and well/reservoir surveillance Shell guidelines associated with remote operations EP remote operations experiences in a number of different assets in Europe, USA and Africa
This paper demonstrates that, for Shell, remote operations is not a remote possibility, but is in the process of becoming a reality across our global upstream operations.
This paper was also prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Denver, Colorado, USA, 30 October–2 November 2011 as SPE-145293-MS.
Reservoir Surveillance and Successful Infill Well Delivery in a Mature Asset
Authors: Zett Adrian , Mukerji Parijat , Ward Mary , Pearse Chris , Houliston Dawn 
Published: September 2011

Abstract
Production Petrophysics plays a key role in reservoir surveillance and field management. This is particularly true for mature assets which present several challenges related to fluid contact movement, connectivity of reservoir layers and well productivity. Identification of infill targets therefore requires an integration of all sub-surface data. This paper presents examples from a mature North Sea field where cased-hole surveillance helped minimize risks in a high cost infill project. The Machar field, located in the UK Central North Sea is a fractured Cretaceous chalk and Palaeocene sandstone oil reservoir. The field development has been carried out in a phased manner due to a high degree of reservoir uncertainty, especially in the eastern flank. Enhancing the seismic sufficiently to fully assess prospects on the east became a priority, and ultimately led to drilling the east flank of the field in 2008.
Machar is a subsea field development and therefore petrophysical surveillance has been restricted due to limited well access and logistical challenges. During the infill drilling, it was therefore decided to use the opportunity and capture cased-hole saturation and production logs in existing wells. This data enabled the asset teams to understand fluid displacement mechanisms and upon integration with LWD and other logs provided the basis for the side track strategy. In particular, location of the imbibition flood front, fracture conduits and differentiation between formation and injection water were critical in the delivery of a successful producer.
Two wells have been drilled on the eastern flank, one in 2008 and another in 2010. Baseline petrophysical surveillance was part of the data acquisition program in both wells. The initial objective was to use such data in Time Lapse mode with later surveillance. However, in-depth work identified immediate use when integrating with LWD and Wireline data.
CO2 Leakage Prevention Technologies
Authors: Eke Paul Emeka , Naylor Mark , Haszeldine Stuart , Curtis Andrew 
Published: September 2011

Abstract
A central challenge of both scientific and regulatory interest is how to ensure carbon dioxide (CO2) is securely contained within a storage site. The fate of CO2 in the subsurface describes the range of processes that progressively trap the CO2. Pure phase CO2 can be trapped within the pore space as (i) residual saturation, and (ii) capillary trapping where the buoyancy forces exerted by a vertical column of CO2 are not sufficient to overcome the capillary forces either within the reservouir rock or to overcome the caprock. Aside from the physical trapping of free CO2, it can be trapped as an aqueous phase. An alternative to injection of pure phase CO2 is to inject CO2 saturated waters which are denser than the unsaturated formation waters thus eliminating the problems associated with buoyancy. Further, in order for the CO2 to be locked away geochemically as mineral trapping, it must first enter an aqueous phase in order for it to be reactive.
Here we explore engineering technologies for enhancing the dissolution of CO2 in formation fluids to mitigate leakage and minimise the risk of CO2 escaping from the storage site. Conceptual process engineering and design of CO2 injection systems downstream were performed with primary aim of rendering integrated injection strategies suitable for use in enhancing permanent storage of CO2 in deep geological formations.
The results of the application indicate that the strategies speed up CO2 dissolution and immobilisation as the period of time needed to achieve immobilisation in the subsurface formation is enhanced by the surface processes engineering. The immobilised CO2 will remain indefinitely in the storage zone even if the integrity of the caprock is not intact.
These innovative engineering technologies provide leakage prevention opportunities which are fundamental to addressing long-term risk management and monitoring issues for CO2 storage sites.
Cross Industry Hydrocarbon Release Analysis
Authors: Li Amy 
Published: September 2011

Abstract
This paper presents the recent analysis results of offshore hydrocarbon releases occurring on the United Kingdom Continental Shelf (UKCS) between 2008 and October 2010. The analysis includes the type of hydrocarbon released, the operating mode during which releases occurred, the release sites, age of installations, type of installations (manned and unmanned; Floating Production Storage and Offloading vessels [FPSOs], Floating Production Facilities [FPFs] and fixed installations) and the underlying causes of the releases. This paper aims to assist the industry to identify where it can best place its resources to reduce the number of hydrocarbon releases.
Managing Process Safety to Enhance Business Performance
Authors: Cockburn-Evans John 
Published: September 2011

Abstract
The oil and gas industry has had a long history of mixed safety performance. And yet, safety has always been an imperative due to the sometimes rather extreme hazards faced by the employees. Recognising this, the industry has made great strides in improving safety performance, as can be seen by the reduced lost time injury rates. The industry has also made remarkable progress in advancing technical and technological capability, but continues to face challenges in preventing major incidents. Investigations from these major incidents have a common thread: a relatively low level of appreciation of risks, muted reactions to near misses and some degree of complacency. In all cases, the origin can be linked to the level of commitment stemming from the highest layers of management.
The hazardous and complex nature of oil and gas extraction and processing is readily apparent, and management within the industry is making good progress in fully recognizing its obligation to make responsible decisions. The type of decision-making required necessitates a structured and systematic way to appreciate risks, to create a culture of learning and to maintain focus and determination to counter process risks in the absence of major crises. Through its experience, DuPont developed a process safety management (PSM) system based on best practices. This system has helped to achieve operational excellence, manifesting in increased productivity, higher quality of deliverables, reduced waste, lower operational costs and enhanced business performance.
This paper will provide recommendations on improving the safety context, as well as implementation of mechanisms that ensure sustainability. Moreover, this paper will discuss specific actions and processes based on DuPont best practices that can be implemented by oil and gas companies to reduce risk and streamline operations. Benefits of this system extend beyond avoidance of catastrophic events and their associated costs. It has been shown that PSM has contributed to increased productivity, higher quality, reduced waste and lowered operational costs.
The extraction of oil and gas is a highly technical mechanical operation that involves volatile and corrosive substances in often extreme conditions. Repetitive acts can lead to complacency, increasing operational risk. Through proper administration of process safety management, it is possible to protect personnel from injury and prevent significant environmental harm, property damage, and business losses, while furthering the ability to achieve performance objectives.
The Role of Asset Integrity and Life Extension in Major Accident Prevention
Authors: Ritchie David M 
Published: September 2011

Abstract
Duty holders and operators of major hazard assets should have in place the required processes, programmes and procedures which coherently:
Prevent major accidents; ensuring risks from major hazards are reduced to as low as reasonably practicable Ensure asset integrity is a continuous process throughout an asset's life Ensure asset life extension is properly managed using defined processes and procedures
This paper describes how, collectively, these processes, programmes and procedures are aligned to a major accident prevention process which is a core element in the management of an asset at all stages of its life cycle.
The primary goal is to ensure that plant and equipment does not, and is not allowed to fail in such a way as to cause or substantially contribute to a major accident.
The requirement to manage assets throughout their life including any life extension period should be mandated by company policy and standards which in ConocoPhillips case recognises the design, operation and maintenance of an asset should be such that its integrity is preserved at an acceptable level of risk throughout its operating life.
Asset life extension is a process that begins when an asset's components wear out, requiring maintenance or repair to maintain a satisfactory operating condition. This begins soon after the asset enters operation for the first time and continues throughout the life of an asset.
However, with increasing age, unchecked asset degradation can become widespread and gradually escalate to a point where significant restoration is required. Consequently, major accident risks may be increased requiring an asset operator's management system to be carefully designed to contain them.
By embedding the Major Accident Prevention Process in the way we design and manage our assets, we ensure that asset integrity is a continuous and forward looking process that supports the case for asset life extension.
The Maule Field: An Economic Small Field Development
Authors: Pyle Jeff , Koster Klaas , Rose Phil , Barker Gregg 
Published: September 2011

Abstract
Apache discovered the Maule field in October 2009 with the 21/10-A52 wellbore drilled from the Forties Alpha production platform. The discovery of a 14m TVD net oil column in Eocene aged Brimmond sands led to the development of the Maule field under the UK government's small field allowance scheme. The field was taken from completion of the discovery well to first oil from a horizontal production well in under 9 months.
The Maule field is located on the western margin of the Brimmond Formation turbidite fairway where re-mobilised sands are also present. Steep dips as seen in the development well and steep seismic features indicate that the Maule field reservoir was formed by remobilsation of Brimmond sands.
The A52 exploration well was drilled on the basis of a seismic amplitude anomaly. This seismic data along with LWD density image data was used to successfully place the horizontal production well which accessed a 114m MD pay section and flowed in excess of 11,500 bopd. A 2010 4D snapshot taken in early July 2010, 5 weeks after production started, identified the source of the well's rapidly increasing water-cut and identified further infill locations.
Despite modest production for an offshore North Sea development the first Maule producer has been an economic success for Apache as a result of integrated subsurface technical work, drilling performance, small field allowance incentives and a sense of urgency.
Increasing Reliability of Cutting/Pulling Casing in a Single Trip
Authors: Hekelaar Stephan , Gibson Kenneth , Desai Praful 
Published: September 2011

Abstract
This paper discusses the tools, technology and methods developed to significantly reduce pipe cutting and recovery time in subsea plug and abandonment operations and in the slot recovery program for existing platforms.
Conventional apparatuses and techniques for cutting and extracting well casing involve multiple trips downhole to run and retrieve the cutting and spearing equipment, because the required tools do not function cooperatively. In certain slot recovery operations, cutting and pulling the casing may be difficult due to firm cement bond, barite settling from drilling fluid in the annulus, or both. Accordingly, such slot recovery operations require cutting the casing several times to locate a friction free point for safe extraction of the severed casing resulting in multiple trips.
The authors describe a recently developed pipe cutting system with multiple sets of cutters which can be selectively activated while the tool is downhole. When one set of cutters wears down, a replacement set can be selectively activated to resume cutting actions. The tool currently has three sets of cutters; however more sets can be added. Also, each set of cutters feature knives dressed with novel inserts made from a specially formulated compound which extends cutter life. Each set has a positive knife return mechanism to ensure full collapse. The tool also enables pressure to be monitored from the surface by means of an indicator device, which registers a pressure drop at the rig floor to indicate a cut has been completed. Additionally, the spearing device can be run in the same drill string and selectively activated to retrieve casing after it is severed.
North Sea field runs involving slot recovery programs in which operators faced stuck casing that required several cuts to locate a free point will be outlined to document tool success. The pipe cutting system performed successfully in all cases thus validating the objective of allowing multiple cuts in the casing and minimizing the number of trips required for casing cutting and recovery operation.