bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiwell Injectivity for CO2 Storage
Authors: Zakrisson Johan , Edman Ingrid , Cinar Yildiray 
Published: October 2008

Abstract
A multiwell injectivity model is necessary to assess CO2 injection potential in subsurface formations. This necessity becomes almost ineluctable when CO2 is injected into low-permeability formations, which requires multiple injection wells in order to compensate a minimum injection rate for commercial projects. The pressure interference between the injection wells located in the same reservoir causes significant injection losses.
This paper examines well interference when injecting fluids with more than a single injector in a porous medium. Two cases of multiwell injection are studied; water injection and gas injection in a water filled reservoir. In both cases the aim is to examine the degree of well interference caused by the number of wells, formation permeability, well spacing, and total injection rate. A steady-state analytical model obtained using the superposition principle is used for the flow of a slightly compressible fluid of constant viscosity and compressibility in a rectangular homogeneous reservoir of uniform thickness, porosity, and permeability. The wells are represented by fully penetrating vertical line sources with a constant well spacing in a regular pattern. The model is used to calculate the required number of wells for given reservoir parameters and total injection rate. The results are compared with those obtained using single-well and multiwell numerical models.
Comparisons show that there is a good match between the multiwell analytical and numerical models for permeabilities higher than 10 mD. It is found that the single-well analytical model underestimates the well numbers compared to the multiwell analytical and numerical models for this range of permeabilities whereas for permeabilities lower than 1 mD it has a good agreement with the numerical model. It is argued that the reason for this should be well interference because the flow in low permeability media is relatively slow, causing less interference between the wells.
Gorgon Project: Subsurface Evaluation of Carbon Dioxide Dsposal under Barrow Island
Authors: Flett Matthew , Beacher Graeme , Brantjes Jeroen , Burt Aaron , Dauth Chris , Koelmeyer Fiona , Lawrence Robert , Leigh Seb , McKenna Jason , Gurton Randal , Robinson IV William F. , Tankersley Terrell 
Published: October 2008

AbstractThe Gorgon Project is a major LNG development to be based in Northwest Australia. Gas will be produced from several offshore gas fields located in the Greater Gorgon Area with processing facilities to be located on Barrow Island. The reservoir fluids of several of the fields contain carbon dioxide (CO2) which will be extracted from the produced gases prior to liquefaction into LNG. The Gorgon Joint Venture participants have proposed to geologically dispose of the produced reservoir CO2 from the gas processed at the Barrow Island LNG plant.The CO2 injection project was extensively documented and subjected to public comment as part of the Gorgon Project Environmental Impact Assessment Process. Following this process the WA Environmental Protection Authority found that the environmental risks associated with the CO2 injection project were acceptable and recommended that CO2 injection must proceed as an integral component of the Gorgon Project.The target formation for geological disposal of this carbon dioxide is the Dupuy Formation, a Jurassic saline reservoir, deep beneath Barrow Island. The evaluation of the Dupuy Formation for the disposal of carbon dioxide was focused on characterising the reservoir and narrowing subsurface uncertainties not addressed by legacy oil exploration and development. Data acquisition was targeted to reduce major subsurface uncertainties including a seismic pilot to assess acquisition methods (including 4-D seismic) and an extensively evaluated appraisal well. Robust geological description, hydrodynamic, static and dynamic reservoir models have been used to gauge the impact of CO2 injection on development decisions. Key drivers for this development have been maximising per well injection of CO2 and ensuring containment of CO2 within the reservoir. Through effective subsurface and economic evaluation, a phased and flexible development plan for CO2 disposal has been developed to meet these objectives.
Stress Estimation at the Otway CO2 Storage Site, Australia
Authors: Bérard T. , Sinha B. K. , Van Ruth P. , Dance T. , John Z. , Tan C. 
Published: October 2008

AbstractWe present an estimation of the full stress state between 0.5 and 2.1 km depth at the Otway CO2 storage pilot site, Australia, where the Cooperative Research Centre for Greenhouse Gas Technologies is conducting a large-scale demonstration project. This estimation is the first step of a geomechanical study on seal integrity. One principal stress is assumed vertical and of magnitude equal to the weight of the rock above, calculated from the density log data. The vertical stress gradient is on average 22.01 MPa/km. Extended leak-off test data, a borehole wall electrical image and dipole sonic log data in the CO2 injector CRC-1 are used to constrain principal horizontal stress orientation and magnitudes. Consistency of the stress model is then checked against the occurrence of breakouts using a mechanical earth model built along CRC-1 well. We conclude that the maximum horizontal stress direction is oriented N141 +/− 9°E. To first order, principal horizontal stress magnitudes both follow a linear trend with depth. Results indicate minimum horizontal and maximum horizontal stress gradients on average equal to 15.98 and 18.13 MPa/km, respectively, corresponding to a normal stress regime.
Preventing Annular Gas Flow in Conjunction with 2 Stage Cementing
Authors: Brooks Robert , Newberry Jack , Cook Paul , Wendlinger Franck 
Published: October 2008

Abstract
The most important purpose of primary cementing is to seal the annulus in order to eliminate communication between subterranean zones and the surface. Drilling through gas formations poses unique risks such as annular gas flow. Annular flow related to poor cementing of large diameter surface casing has been identified as one of the most frequent causes of well control incidents. Many primary cementing jobs fail to stop interzonal communication, and poor cement bonding has been credited with the most significant cause of annular casing pressure in outer casing strings. Statistics worldwide indicate there are thousands of wells with sustained casing pressure that potentially lose hydrocarbon reserves, or leak gas at the sea floor.
Annular gas flow during, and after, cementing is a frequent problem in areas where oil and gas reservoirs are the primary producing reservoirs, shallow gas formations are present, and leak-off tests are not regularly performed. When zonal isolation in gas wells is not achieved, gas can migrate behind the casing, thus charging shallower formations, which become a costly problem when they are drilled into unexpectedly. Several techniques are currently used to control annular gas migration with each delivering varying degrees of success
These methods involve drilling processes, cementing systems, and mechanical barriers. This paper focuses on the use of an inflatable casing annulus packer (CAP) to seal the annulus in conjunction with a cementing port collar (PC) above the gas migration source. If the primary cement job does not achieve the required displacement efficiencies, and satisfactory results, a second stage cementing option using the port collar is still a possibility.
As an ongoing development to allow for the reduction of the number of casing strings in a well, integration of a metal-to-metal (MTM) sealing cementing port collar and CAP in a premium production casing string, with MTM sealing connectors, is used. This light architecture well design effectively reduces overall well costs in addition to improving HSE issues.
By utilizing this approach no gas migration has been detected to date in over 357 wells completed using casing annulus packers and port collars. Based on prior experiences and costs associated with remediation of a well with annular gas flow, the mechanical control technique has effectively reduced the overall well costs in addition to drastically improving HSE issues.
Study on Minimum Air Flux for In-situ Combustion into Light Oil Reservoir
Authors: Takabayashi Katsumo , Onishi Takeshi , Okatsu Koumei , Maeda Haruo , Moore R. Gordon , Mehta S. A. (Raj) , Ursenbach Matthew G. 
Published: October 2008

Abstract
In-situ combustion projects in heavy oil reservoirs were started early part of the last century. The number of projects was increasing toward 1960s. More than 120 projects were carried out in U.S. at that time. After 1970s, it plunged to less than one-tenth. But in the middle of 90s, it began to increase again. The main reason for this rise was an increase in-situ combustion projects in light oil reservoirs and recently they have been increasing.
Since 1999, our study of the light oil reservoir from the Minami-Aga oil field in Japan has continued. Now we focus our attention on minimum air flux which is needed to sustain a combustion front. The minimum air flux will be used to design an air compressor for a pilot-project.
A discussion of minimum air flux for heavy oils was published by Nelson and McNeil5. It is believed that a mechanism of combustion for the light oil is different from the heavy oil. It is also believed that the light oil's combustion front is less stable than the heavy oil's. Therefore in our case to estimate the minimum air flux, it might be better to take a different way. In this paper, a thermal simulator was used to estimate the minimum air flux. Prior to a simulation study some High Pressure Ramped Temperature Oxidation (HP-RTO) tests with our oil were carried out to obtain combustion parameter. A reaction model in the thermal simulator was obtained based on the HP-RTO tests results.
Challenges in Completing Long Horizontal Wells Selectively
Authors: Ritchie Barry , Abbasy Imran , Pitts Michael , White Brendan , Jaafar M. Rushdan 
Published: October 2008

Abstract
Although drilling technology is now able to deliver ultra-long horizontal wells, completion technology has been slower to evolve. Running long liners, effective stimulation and completions are some of the areas that require more attention.
The paper discusses some of the challenges in the development of the Al Shaheen reservoirs offshore Qatar and how they were overcome. Some of these wells have a step-out in excess of 30,000 feet with a TVD of 3,100–3,500 feet and thus they offer some unique challenges.
Running and cementing liners to these depths is difficult and some of the methods to effectively achieve this are discussed. Perforating guidelines are presented that allow sand control without having to resort to conventional sand control practices. Stimulation of such long reservoir sections is a particular challenge and a fine balance must be struck between acid coverage and cost, both for barefoot and perforated intervals. The so-called Q-CAJ technique of acid distribution is presented, which has allowed acceptable stimulation despite these conditions. The technique also offers opportunities to stimulate long horizontal boreholes more effectively and at lower cost.
Some of the wells are completed with multi-zone selective completions, which push the design limit of equipment. A number of such intelligent wells have been completed successfully and more aggressive wells are planned. In order to optimize the development cost, dual-lateral wells have also been drilled with complete control over each lateral. Discussed are some of the underlying completion techniques such as running completion in stages, use of mechanical latches, hydraulic control line wet connects, interval control valves and limitations imposed by control lines. The paper concludes with some of the challenges that have yet to be overcome.
Successful Application of Horizontal Well Completions for Development of Low Permeability Gas Reservoirs in a Complex Fluvial Deltaic Environment – A Case Study
Authors: Hazman Harry Alam , Damayanti Shinta , Wijanarko Andre , Arifin Zainal , Rahardjo Heriadi Buhron , Nikijuluw Robert , Sable Gary J. , Narayanan Ram K. , Schmohr Donn , Rylance Martin 
Published: October 2008

Abstract
VICO Indonesia is the operator of the Sanga-Sanga Production Sharing Contract located onshore of the Mahakam delta, East Kalimantan, Indonesia. The PSC has produced over 70% of the OGIP (original gas in place). The fields are relatively mature with the remaining gas resources locked up in either pressure depleted reservoirs or in low permeability reservoirs where conventional techniques have not been very effective in depleting these resources. During 2006, VICO decided to perform a pilot development of the larger/tighter reservoir tanks, utilising the horizontal completion technique as the preferred completion approach.
To date VICO has successfully drilled and completed 5 horizontal wells, one in the Semberah field (S77H) and four in the Nilam field (N228H, N230H, N238H & N240H). The Semberah S77H well was drilled and completed in 2006 at a relatively shallow depth (~ 8000 ft.TVD.SS), in order to demonstrate the applicability of horizontal drilling technology within VICO. The four subsequent wells were drilled in the Nilam field, to depths of ca. 12,500 ft.TVD.SS. The N228H & N238H wells were drilled to test the productivity of horizontal wells at higher reservoir pressures; where condensate banking was thought to be a contributory factor to the dramatic transient and low deliverability seen from conventional vertical wells. Whereas the N230H and N240H wells, were drilled to test the productivity of horizontal completions in the depleted tanks where condensate banking may not be such a significant factor. All five of the wells are currently producing at relatively stable rates with significantly less decline, when compared to conventional offset wells. The initial gas production rates, that were achieved, were significantly higher than conventional wells producing from the same reservoirs and the total reserves recoverable per well are estimated to be 2 – 3 times higher than a conventional well.
The paper will describe in detail the candidate selection criteria, well design, well placement, drilling risks, tool reliability and the challenges steering a horizontal well in a geologically complex environment with high degree of reservoir uncertainty.
Using Chemical Tracers for Flow Profiling a Subsea Horizontal Well with an Open Hole Gravel Pack Lower Completion: Field Results
Authors: Bakhshi Ali , Scaife Peter , Mickelburgh Ian 
Published: October 2008

Abstract
This paper presents the first case study on using chemical tracers for flow profiling a subsea horizontal well with an open hole gravel pack lower completion in Enfield field, Australia. The principle of the technology involves positioning a number of different tracer materials, each at specific locations along the length of lower completions, prior to lowering downhole. The tracers are selected to be soluble in either crude oil or water. Upon well start up, oil samples are taken at the surface over a short period of time. These samples are analysed to determine tracer presence. The presence of one or a combination of unique tracers within the oil sample, along with the known location of each tracer downhole, allows qualitative information to be generated about fluid flow in the well.
Chemical tracers for flow profiling were chosen for ENA03L1, an oil well intersecting a number of fault blocks in the south of the Enfield field to: Provide direct proof of fluid flow from different fault blocks;Improve understanding of well clean up of a horizontal well, especially the contribution from the toe of the well; andDetect the location of water breakthrough.
Results showed that within four hours of the initial clean up, all oil soluble tracers were detected, providing positive confirmation that the intervals tagged, including the toe of the well, were contributing to the overall production.
Using tracers for flow profiling horizontal well provides the following benefits: Enables flow position to be verified in long horizontal wells; andComparatively inexpensive when compared to horizontal well production log costs.
This case study recounts the design, installation, analysis, results and subsequent learnings of the project.
Integrating 4D Seismic Data with Production Related Effects at Enfield, North West Shelf, Australia
Authors: Ali Amna , Taggart Ian , Mee Benjamin , Smith Megan , Gerhardt Andre , Bourdon Laurent 
Published: October 2008

Abstract
The Enfield field has a 160 m oil column located between a medium sized gas cap and a water/leg aquifer system. Enfield is undergoing an active water-flood utilizing both up-dip and down-dip water injection. The water-flood reservoir management of such a field requires timely information concerning reservoir pressures, water-flood sweep and movement of gas and water contacts. Conventional reservoir monitoring practice obtains this information by monitoring at the wellbore. Such approaches require significant time and water-cut development to determine how the reservoir and water-flood is performing and provide little spatial information as to how the water-flood is affected by faults, preferential pathways and structural variation. 4D seismic methods represent a powerful tool to assist reservoir management. This work describes the planning, implementation of an early 4D program for the Enfield water-flood and history matching process. Pre-development feasibility work indicated that Enfield had rock properties favourable for 4D monitoring as reservoir sands are acoustically soft and identifiable with seismic amplitudes. Post-production, early 4D monitoring has provided unique and timely insight into water movement both within the reservoir and through active fault networks that wellhead data alone would not provide. This work has shown the benefit of 4D in the following areas; tuning of injected water flows to a northern fault/aquifer system, locating new injector producer pairings, improved utilization of geologic and seismic barrier and baffle features into the history matching process and finally showing how the seismic response to up-dip water injection, around a key injector, was more subtle and supported the choice of imbibition relative permeability relationships and trapped gas saturations. Validation of insights was provided by the use of synthetic seismic modeling of simulation results.
Successful Field Application of Novel, Non-Silicone Antifoam Chemistries for High Foaming Heavy Oil Storage Tanks in Northern Alberta
Authors: Wylde Jonathan J 
Published: October 2008

Abstract
Substantial foam formation was being experienced by two operators in several heavy oil leases in Northern Alberta. This 10 – 12 API crude had a large foaming potential and unique foam formation mechanism. Crude oil passed from the wellhead, via a short flowline to a pair of hydrostatically balanced and heated storage tanks. The storage tanks heated the crude oil from approximately 50°C to 85°C and in doing so, caused gas breakout and degassing which resulted in the formation of a thick, persistent foam in the top of the tanks. The foam would enter the transportation trucks and end up at the local battery and create carry over and separation problems in the process systems.
Silicone antifoam products were not acceptable due to both their poor environmental profile and also the influence these large molecules had at the refinery where the crude oil was shipped for (predominantly) asphalt manufacture.
A wide range of chemistries were tested including phosphate based products, ethoxylated and propoxylated esters, polyethylene glycol esters and oleates, alcohols, fatty alcohols and ethoxylated and propoxylated alcohols. One of the major challenges detailed in this paper is that all products had to be freeze protected to −40°C. This was significant due to many anti-freeze chemicals affect the efficacy of antifoam chemicals.
This paper details evolution of testing leading to the field application of this combined defoamer / antifoam chemistry. Initial laboratory screening is included which describes a unique laboratory test method designed to mimic more accurately the foam formation environment in the field. The paper goes onto illustrate the field trial evaluation as well as the case histories of full field implementation of the highest efficacy products.
Design and Implementation of a Caustic Flooding EOR Pilot at Court Bakken Heavy Oil Reservoir
Authors: Xie J. , Chung B. , Leung L. 
Published: October 2008

Abstract
The Court Bakken heavy oil reservoir (17 °API) in Saskatchewan has been under successful water flooding for many years. Laboratory studies have indicated that caustic flooding can enhance heavy oil recovery significantly after water flooding. This paper describes design and implementation of the first caustic flooding pilot in a heavy oil reservoir of this viscosity range in the Western Canadian basin. It reviews results of laboratory studies and a single well test. It also discusses challenges experienced at Court during the early piloting phase.
Development of a Higher-order Finite Volume Method for Simulation of Thermal Oil Recovery Process Using Moving Mesh Strategy
Authors: Ahmadi Mohammad 
Published: October 2008

Abstract
Numerical simulation of thermal recovery processes like steam injection often involves localized phenomena such as saturation and temperature fronts due to hyperbolic features of governing conservation laws, Treating more efficiently convective terms could help to diminish spurious oscillation and/or numerical dispersion and better tracking of discontinuity shocks. But in regions near the shock numerical dispersion can only be removed by the use of very fine uniform grids with many grid blocks. To avoid expensive solution of such a finely girded domain, we develop a moving mesh approach combined with higher order up-winding schemes.
Numerical solver here have been employed is Finite volume method. A MMPDE(moving mesh PDE) is solved associated with physical PDE's of steam injection process in order to relocates the mesh nodes to concentrate them in regions of sharp discontinuity and Equi-distribute a measure of error-estimate (monitor function) over the meshes. Solution will advance more rapidly on course meshes and fluxes at the coarse-fine grid interfaces are refined to guarantee mass conservation.. Since the region surrounding the sharp discontinuity and requiring high resolution consists of only a small fraction of the entire domain, prescribed locally time stepping results in a great saving in computational time. Specific features of moving mesh methods like monitor-function smoothing, control of mesh widths and readjustment of solutions further to mesh movement are addressed. Numerical experiments are carried out to demonstrate the efficiency and robustness of the proposed method in 1-D and 2-D. However numerical results for moving coordinates are compared with those obtained from simulation on non-adapted mesh framework. Preferences of higher-order solvers over lower-order ones in terms of shock capturing is being investigated.. Although we have limited our modeling to steam flooding process, but simulation demonstrates main features of our approach, applicable to other EOR processes such as VAPEX, SAGD, and In Situ Combustion Process.