bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cost Effective Deepwater Well Construction— A Case for Managed Pressure Drilling With Casing
Authors: Oyeneyin M. B. 
Published: December 2009

Abstract
Engineers now face increasing challenge of drilling in Ultra Deepwater environments which form the cornerstone of future field developments. The deepwater environments are characterised by complex temperature profiles and geological features such as High Pressure-High Temperature (HP-HT) with very narrow pore pressure-fracture pressure window; Shallow unconsolidated reservoirs with very high overburden; Combination of ‘'flexible" lithologies. In these environments the use of overbalanced drilling techniques becomes difficult as the tolerance between formation pressure, wellbore pressure and the pressure at which the formation will fracture becomes very small. This can lead to severe drilling problems with attendant increase in drilling costs to possible loss of well control itself. These deepwater environments can benefit from Managed Pressure Drilling (MPD) when effectively combined with casing drilling technique but its uptake has been rather slow.
For the industry to develop a managed pressure drilling capability that will allow today's generation of complex wells to be drilled safely with casing, it is necessary to develop models that will accurately simulate the MPD process and to embed these models within an easy to use, intuitive well design package for pre-planning and as a real time tool to monitor, diagnose and optimise downhole operations and provide forward simulations based on rig and downhole data.
This paper presents the unique algorithms developed to simulate the MPD process and to analyse the effects of soft issues on the wellbore flow and pressure regimes and impact on torque/drag.
The algorithms developed have been validated with live well data including pump rates, fluid properties and especially PWD and pump pressure data. The predictions and actual data have been found to be in very close agreement.
The results of algorithm validation are presented to illustrate how the simulator can be utilised for real time design as well as process optimisation especially for casing drilling versus standard drillstring scenario. Highlights of the effects of the complex relationships between eccentricity, rotation and fluid rheology at bottom hole and riser conditions are also presented to illustrate the drilling process optimisation. The paper is concluded with guidelines on MPD operating windows for different scenarios and a brief description of the system architecture of the MPD Simulator – The MPDEEP.
Implementation of Integrated Network Optimization Model for the Mumbai High Field—Crucial to Field-Wide Optimization
Authors: Jha Anand Kumar , Barua Santanu , Agrawal Vikas , Agarwal Gunja , Kumar Ravi , Moitra S. K. , Negi G. S. 
Published: December 2009

Abstract
The giant ONGC Mumbai-High offshore field produces about 250,000 bopd (60% water-cut) from 700+ wells through 110+ unmanned production platforms. The production platforms are connected by subsea flow lines to 6 processing platforms where the oil, water and gas are separated. More than 80% of the wells in the field are on gas-lift.
This paper discusses an integrated-network-modeling-and-optimization approach to overcome known drawbacks of single well gas-lift optimization. The new higher fidelity model captured the interactions between wells, flow-lines and platforms, field-wide. Using this approach, previously hidden opportunities for significant production improvement were identified. The model indicated a possibility of significant production increase (2 to 4%) and production efficiency improvement (significant reduction in lift gas requirement), which could be achieved by better allocation of lift gas and repair and redesign of the sub-optimal gas-lift wells. The latest available field implementation results are also presented.
Currently, in the absence of full-loop control-automation of the gas-injection rates/pressures, logistical challenges made it impractical to simultaneously implement the calculated optimum settings field-wide. The network interactions are highest at the production-platform level between adjacent wells and connecting shared flow-lines. So, from practical implementation considerations, optimum gas-injection rates were calculated and simultaneously implemented at the production-platform level, one (or a group of few connected) production platform at a time, with little or no compromise on the quality of the solution or on the validity of the approach.
To date, actual optimization implementation changes in 14 of the 110+ platforms (160 of the 700+ wells) indicated immediate production increase of over 2000 bopd and significant reduction in lift gas requirement. Based on these early indications, it is envisaged that the field-wide oil production gain can possibly be as high as 6%.
Additionally, this paper discusses the challenges and recommended approaches with regards to sustainable model maintenance, solution implementation and workflow. Status of control automation and on-line modeling plans (planned for implementation in future) are also discussed.
Optimised Completion of a Produced Water Re-injection Infill Well
Authors: Mason John , MacLeod Innis 
Published: December 2009

Abstract
A produced water re-injection (PWRI) well, PWRI-3, was drilled and completed from the Eastern Trough Area Project (ETAP) North Sea platform in 2008. Two previous wells, PWRI-1 and PWRI-2, were drilled early in field development to inject all produced water into a Palaeocene sandstone aquifer at 2800mTVDss, 125degC and 4100-4500psig reservoir pressure.
As the fields have matured, increasing volumes of produced water need to be injected as expected. At the same time, declining injection rates into the two disposal wells has resulted in the fields becoming limited on water disposal. Oil production constraints due to produced water disposal have developed since about 2005. As a result, planning for a third PWRI well was kicked-off in 2006.
This paper details the design, installation and initial performance of PWRI-3, focussing on the well completion. As a single infill well requiring mobilisation of a heavy-duty jack-up, the requirement for PWRI-3 was to deliver a high quality, high integrity, high rate, long life water injector. The multiple sources of produced water from the ETAP fields create a complex chemical cocktail, requiring the completion to cope with varying levels of CO2, H2S, chloride, sulphate, barium and production chemicals. A cemented 7" 13%Cr liner, fibreglass-lined 7" injection tubing, alloy 718 completion jewellery and a fully clad 7" tree were selected. Specific measures were taken to minimise risk of wireline damage when running perforating guns through the injection tubing. Concerns about managing increasing pressures in the Palaeocene led to the installation of a downhole gauge, to help maintain high injection rates within the limits of caprock fracturing pressures.
To understand injection fracturing and to maximise injectivity, a specific sequence of perforating and bullheading was used. To reduce the environmental footprint of the rig activity, over 2500bbl of contaminated seawater (containing residual oil based mud from the mud-to-brine wellbore displacement) was bullheaded into PWRI-3 during this rig injection testing.
Mitigation of Vapor Cloud Explosion Effects by Inhibitors
Authors: Hoorelbeke Pol , Mukharror Darmawan Ahmad 
Published: December 2009

Abstract
Devastating vapor cloud explosions have occurred all over the world since decades. Avoiding this type of major accidents is a real challenge for the oil industry. Total performed theoretical and experimental research in the potential to mitigate the effects of vapor cloud explosions with inhibitors. Experimental results in 50 m3 module at Sotra (Norway) showed that overpressure reduction up to 90% could be obtained.
New Single-Trip, TAML Level 4, Multilateral Junction Technology Reduces Well Costs in Norwegian Sea Subsea Well—A Case History
Authors: Balstad Olle , Glaser Mark , Heng Tage 
Published: December 2009

Abstract
The installation of the first single-trip Technology Advancement for Multilaterals (TAML) Level 4 multilateral (ML) junction system was completed in a subsea, gas-injection well. It was drilled to support oil production from the Tilje and Ile formations in the Smørbukk Sør field in the Norwegian Sea, approximately 193 km offshore in 300 m water depth.
After injecting for ten years, the well will be converted to a gas producer from the same formations. Because of the Norwegian Sea's environment, the multilateral system had to be low risk and simple to install, with the capacity to minimize pipe trips and withstand the heaving seas. The casing exit had to be long enough to accommodate running a rotary steerable system through the window to drill the lateral to TD. This window had to be milled in a single trip in 13%Cr 110 casing followed by milling into the Garn 4 hard-impermeable sandstone with possible quartz stringers.
Hollow-whipstock technology has been employed for more than ten years in the North Sea, but a new system, designed to be installed in a single trip—-a savings of two pipe trips—-was selected for this project. The hollow whipstock was perforated through after the liner was installed in the lateral to regain hydraulic access to the main bore below the junction. The hollow whipstock was used for the milling and production/injection phases and was not retrieved, saving an additional pipe trip. The well completion used several cementing and completion products and services, including liners with screens and swell packers. Stage cementing was performed to isolate permeable formations between the junction and the reservoir.
The well was successfully completed and gas injection began with increases in production being noted from the adjacent producing wells. Although it was unusual to use a multilateral well for gas injection, the technology proved that it can be applicable to any multilateral well requiring a Level 4 junction.
Successful Practices and Development of Polymer Flooding in Daqing Oilfield
Authors: He Liu , Jinling Li , Jidong Yan , Wenjun Wang , Yongchun Zhang , Liqun Zhao 
Published: December 2009

Abstract
Basing on improving volumetric sweep efficiency and reducing channeling and breakthrough, polymer flooding can yield a significant increase in oil recovery when compared with water flooding. Polymer flooding has been conducted successfully in 13 field tests since 1989 and has been commercially used in the following years. Field tests show that the recovery improving with increasing of concentration and injection volume. By applying polymer flooding, the main formation recovery of Daqing oilfield has reached more than 50%. It is 10% ~ 15% higher compared with the other oilfields. In the 20 years' practices of polymer flooding, Daqing Oilfield has developed a complete series of techniques covering reservoir, production, facilities engineering and produced liquid treatment. Polymer flooding has gradually become an important technique to maintain the high and stable production capability of Daqing Oilfield. Daqing oilfield, being the largest polymer flooding field in the world, has 37 polymer flooding areas which contain nearly 9000 wells by the end of 2005. Now, polymer flood production has achieved 1×109t/a in Daqing Oilfield. In this paper, the reservoir condition, pilot test, solution production and injection, production technology and produced liquid treatment technology are described.
CO2-ECBM/Storage Activities at the San Juan Basin's Pump Canyon Test Site
Authors: Koperna George J. , Oudinot Anne Y. , McColpin Glenn R. , Liu Ning , Heath Jason E. , Wells Arthur , Young Genevieve B. 
Published: December 2009

Abstract
The Southwest Regional Partnership on Carbon Sequestration (SWP) is one of seven regional partnerships sponsored by the U.S. Department of Energy (DOE) that collectively includes more than 350 organizations spanning 40 states, three Indian nations, and four Canadian provinces. The objectives are to determine the most suitable technologies, regulations and infrastructure requirements for carbon capture, storage and sequestration in different areas of the country. In Phase I of the partnership program, significant sources of greenhouse gas emissions were inventoried, potential geological sequestration sinks identified, and small-scale sequestration demonstration opportunities developed. Many of these small-scale pilot demonstrations are currently being implemented as part of the Phase II program. One of the three geo-sequestration pilots for the SWP involves CO2 injection into a deep, unmineable coalbed at the Pump Canyon site located in the San Juan Basin of northern New Mexico.
At the demonstration site, a new CO2 injection well was drilled into the late-Cretaceous Fruitland coals within an existing pattern of coalbed methane production wells. CO2 is currently being injected into the coal at pressures not to exceed the permitted injection pressure, and a variety of monitoring, verification and accounting (MVA) methods are employed to track the movement of the CO2. Some of the MVA methods include continuous measurement of injection volumes, pressures and temperatures within the injection well, coalbed methane production rates, pressures and compositions at the offset producer wells, tracers in the injected CO2, time-lapse vertical seismic profiling, surface tiltmeter arrays, a series of shallow monitoring wells with a regular fluid sampling program, and surface measurements of soil compositions, CO2 fluxes, tracers, etc. In addition, a detailed geologic characterization and reservoir modeling has been implemented in order to reproduce and understand the behavior of the reservoir. To date, the injection is still on-going and no CO2 breakthrough has occurred.
This paper provides a description of the Pump Canyon CO2-ECBM (enhanced coalbed methane) and sequestration demonstration field activities with particular emphasis on the lessons being learned.
The Use of LWD Data for the Prediction and Determination of Formation Pore Pressure
Authors: Greenwood Jeremy , Russell Rick , Dautel Mike 
Published: December 2009

Abstract
The ability to predict and determine formation pressure has been an important issue since the beginning of the industry. This issue has become of increasing importance in deepwater environments where the relationships between increasing pore pressures, formation fracture gradients, and ultimately wellbore stability becomes of critical importance and can determine whether or not a well can be successfully drilled to total depth (TD).
Pre-drill modeling using seismic, structural, and geological data can be used to attempt to predict pore-pressure regimes. Traditional methods of monitoring pore pressure while drilling have relied on methods, such the use of drilling exponents, and other indirect methods, including the monitoring of connection gases and observations of cuttings shapes. These methods are often imprecise, and their success depends on the actual pore pressure generation mechanism.
The development of new logging-while-drilling (LWD) technologies in recent years has added powerful new tools for the accurate determination of pore pressures and wellbore stability. LWD resistivity and sonic measurements can indicate overpressure in shale sequences. Measurements in hole sizes as large as 30 in. make it possible to establish compaction trends in deepwater wells from near the seabed. Direct measurements of formation pressure can now be made with LWD formation pressure tester tools, which can accurately measure formation pressures directly while drilling and, when used with pressure-while-drilling (PWD) measurements, can precisely manage effective mud weights in narrow mud weight window environments.
Advanced LWD imaging technology can now be used to evaluate wellbore stress fields, which can enhance the understanding of hole stability and overpressure generation mechanisms. This paper reviews the use of LWD sensors for pore pressure analysis and uses case histories to demonstrate their application and value.
Contacting the Reservoir—Benefits of Horizontal Open-Hole Completions
Authors: Yakeley Sean , Wood Ed , Knebel Mark 
Published: December 2009

Abstract
Due to the ever-increasing demand for oil and gas, it is becoming more evident that getting the most out of the reservoir is crucial. For years, wells were drilled vertical or deviated, but horizontal and extended-reach trajectories are gaining more prominence. While the objective is to gain more access to the reserves, often the past methods of completions simply were not viable. In deviated wellbores, cased and cemented liner applications are difficult to obtain a good cement bond with the formation, and the inherent near-wellbore damage associated with cementing can lead to costly workover and stimulation treatments. Thus, open-hole completions are becoming more acceptable as the primary completion of choice.
This paper will discuss the benefits of gaining as much contact with the reservoir as possible to create maximum drainage. It also will cover completion solutions (turnkey) that have been deployed around the world to better optimize recovery. Case histories will be provided that include multi-stage fracturing with swellable packers, inflow control devices with mechanical-set packers, geothermal hook-ups with openhole anchor, and multilateral completions with sand control and zonal isolation.
Computational Mechanics Based Workflow and Toolkit to Manage Deformable Reservoir Developments
Authors: Kristiansen T. G. 
Published: December 2009

Abstract
The standard workflows for predicting field performance in the oil and gas industry is not effective when dealing with highly deforming reservoirs. The definition of highly deforming reservoirs with high risk is not well defined, but these fields typically produce development surprises like casing deformations, drilling problems, well failures and in some cases reservoir performance prediction challenges. In cases like this, production from wells can cease although the upfront reservoir flow models have predicted many years of production and revenue. When the deformation is substantial enough, it will also result in surface subsidence that could impact surface facilities, platforms, pipelines and environmental sensitive areas. This paper presents a more robust workflow and toolkit for these challenging reservoirs than the traditional industry workflows used most often today. The workflow is expanding the traditional workflow to also include computational geomechanics as a critical part of the field performance prediction and management. The workflow and toolkit is illustrated by a field case, the Valhall field, where substantial cost savings already have been experienced from implementation of the workflow and toolkit.
Environmental Risk Management Capability: Advice on Minimising the Impact of Both Sonar and Seismic Offshore Operations on Marine Mammals
Authors: Mollett A. , Schofield C. , Miller I. , Harwood J. , Harris C. , Donovan C. 
Published: December 2009

Abstract
There is growing concern about the effect of noise pollution from Offshore Operations on whales, dolphins, porpoises and other marine fauna both in the scientific and political communities. The general public, media and key decision makers are becoming more aware of the potential impact of such operations and this is increasing the pressure on organisations to manage their acoustic impact on the marine environment.
The Environmental Risk Management Capability (ERMC - a software package developed by BAE Systems in collaboration with the Sea Mammal Research Unit (SMRU) and the Centre for Research into Ecological and Environmental Modelling (CREEM) at the University of St Andrews) is the first system to provide a quantitative, robust and repeatable risk assessment method of the potential impact of sonar on both human divers and marine fauna. To assist in the effective management of this impact, ERMC can provide the user with recommendations of potential mitigation measures, and more importantly supports a basis from which the user can continue to use active sonar whilst complying with their operating policies and legislative obligations to protect the environment.
This paper will discuss how ERMC can be employed to provide a risk assessment for both sonar and seismic offshore operations which introduce sound into the marine environment. It will also discuss whether such an approach would provide a more flexible and reliable outcome to methods commonly in use today.
Slug Control With Large Valve Opening to Maximise Oil Production
Authors: Ogazi A. I. , Cao Y. , Yeung H. , Lao L. 
Published: December 2009

Abstract
Severe slugging in an offshore riser pipeline imposes a major challenge to production and flow assurance in the oil and gas industry. Riser top valve choking has shown effectiveness in eliminating severe slugging. However, most manual choking and active control techniques were tuned by trial and error resulting in operation at a smaller than required valve position. This imposes unnecessarily high back pressure on the riser-pipeline which leads to reduction in production. One way to overcome this problem is to design the active control system to operate at a large valve position. However, at such an operating point, the riser pipeline system is naturally open-loop unstable associated with severe slugging flows.
In this work, an approach to tune a robust PID slug controller at an open-loop unstable condition is proposed. Firstly, at an open-loop unstable operating condition, a reliable linear model is derived from the nonlinear simplified riser-separator model (SRSM) developed in previous work. Then, a robust stabilizing PID controller is designed based on the linearised model.
The controller was successfully applied to a 2" laboratory riser at Cranfield University and a 8" generic industrial riser system modeled in the commercial simulator, OLGA. OLGA simulation on the industrial riser system shows that the proposed approaches not only can eliminate severe slugging but can also increase oil production. It also shows that the percentage improvement in oil production compared with manual choking will increase as the well pressure declines. This means that even more can be gained by adopting active slug control for mature oil fields than for relatively new fields.
The result is very significant for mature fields which are susceptible to severe slugging and low oil production due to declining reservoir pressure.
Reelwell Drilling Method—A Unique Combination of MPD and Liner Drilling
Authors: Vestavik Ola , Kerr Scott , Brown Stuart 
Published: December 2009

Abstract
The Reelwell Drilling Method is developed to improve the capability to drill wells through difficult pressure zones, to solve hole cleaning problems and to increase the ERD horizontal displacement. The method uses a concentric drill string and new downhole tools for improved downhole pressure control. The method was recently used for deepening of a well at Ullrigg in Stavanger, Norway. Here the 8 ½" hole section was drilled with a downhole motor and MWD to verify the capability for directional drilling and for downhole pressure control.
The results from the drilling operation show that the Reelwell Drilling Method has successfully verified all the pilot well drilling objectives:
– Excellent interaction with conventional mud pulse MWD. – Full directional drilling control. – Precise downhole pressure control, including the capability for downhole pressure isolation.
The new equipment and procedures have been reviewed and certified by DNV, and the plain version of the Reelwell Drilling Method is now ready for commercial applications. The liner drilling version is planned to be qualified within short time.