bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Integrated Model for the Design and Evaluation of Multiwell Hydraulic Fracture Treatments for Gas-Condensate Reservoirs
Authors: Valencia K. L. , Chen Z. , Rahman M. K. , Rahman S. S. 
Published: December 2007

Abstract
This paper presents a hydraulic fracture treatment design optimization scheme which integrates a hydraulic fracture geometry model, a production model and an economic model. The hydraulic fracture geometry model is used to determine the final fracture geometry and select the treatment parameters for a given stress and reservoir condition. Production from the treated well is estimated for pseudo-steady state condition using a model equivalent to a compositional simulator. A genetic-evolutionary optimization algorithm is used to obtain the optimum treatment parameters for maximum production or NPV. The integrated model has been used to investigate different field scenarios of a multiwell gas-condensate reservoir, including optimization of well locations and hydraulic fracture treatment parameters for any well type, achievement of target production and maximization of NPV with simultaneous minimization of the associated treatment costs.
Optimizing Oil Recovery of XJG Fields in South China Sea
Authors: Luo D. , Jiang Z. , Gutierrez J. , Schwab K. , Spotkaeff M. 
Published: December 2007

Abstract
China National Offshore Oil Corporation (CNOOC), Shell and Phillips China Inc. (PCI) are partners in the development of XJG oilfields located in the South China Sea. The XJG fields are considered to be in the mature phase and challenging PCI (the field operator) with lifting and surface treatment problems due to high water cuts, and the limited amount of slots available in the existing platforms for infill drilling.
A sandstone reservoir with average permeability over a Darcy and strong bottom water drive aquifer support is experiencing water breakthroughs from high permeable layers leaving hydrocarbons pockets behind. Typical completions include sand control devices such as gravel packs and Fracpack inside 9–5/8" casing.
The following list briefly summarizes the main challenges presented by the XJG fields at this stage: Total production close to the limit of surface treatment facilities: 550,000 BFPD.No more slots available for infill drilling, only 1 left reserved for an ERD well.Sand production aggravated due to wells producing at high water cuts.Overall oil recovery still below expected objectives.
PCI created a team including engineers from a service company working toward the common objective of "Maximizing Oil Recovery" in XJG fields making use of state of the art simulators, tools and innovative technologies specially tailored by technology centers to provide reliable answers in South China Sea completions and formation environments.
Reservoir modeling enabled the team to successfully identify remaining hydrocarbon areas in the fields. Resistivity measurements confirmed formation fluid saturations through the relatively large casing with high level of confidence. Reservoir modeling and resistivity measurements behind casing along with the innovative Geosteering tools and techniques helped plan and execute drilling new wells or sidetracking existing wells with high water cuts, effectively increasing oil rates and ultimate field oil recovery.
Encouraging results from this project along with other actions taken by PCI in the field have achieved an outstanding increase of 28 % in oil production of the new sidetracks while reducing the total amount of water at surface (in excess of 17,000 BWPD), saving PCI major expenditures on fluid treatment and/or upgrading platform facilities; benefiting from teamwork implementing innovative techniques in existing assets maximizing oil field recovery at effective cost.
Laboratory Study on MEOR After Polymer Flooding
Authors: Shi Mei , Wei Li , Liao Guangzhi , Han Peihui , Hou Zhaowei , Chen Xinghong , Wang Ying 
Published: December 2007

Abstract
Great advancement has been achieved with polymer flooding after water flooding to enhance oil recovery in Daqing oil field in China. By using polymer flooding, the oil recovery can be improved 12%, and the total oil production is 10 million tons per year in Daqing oil field. However, there is still about 50% remaining oil kept in oil-bearing formation after polymer flooding. This paper gives the method of Quarternary Oil Recovery by using MEOR succeeding a polymer flooding. In this paper, several kinds of bacteria that can grow with polymer and crude oil as the carbon source have been screened. These bacteria are different from that of growing with carbohydrate as the only carbon source used in MEOR before. Evaluation was made on the physiological and biochemical characteristics of the screened bacteria, the ability of their degrading oil and polymer, the ability of their producing bio-surfactant, and on the core displacement test. The results show that the light component and the rheological property of crude oil have been increased due to the action of the selected bacteria, the paraffin content, the gel content and the freezing point of crude oil have been decreased. Also, due to the action of the bacteria, the acid value of oil has been raised by 64.5 times and the initial boiling point has been reduced 80°C. Moreover, the Newtonian Index, Delta viscosity and EOR Index have been increased. Core displacement shows that oil recovery can be improved 5% or 13% by using MEOR or with the following ASP system respectively. All of the experiments can be repeated perfectly.
Analysis of Oil Recovery by Spontaneous Imbibition of Surfactant Solution
Authors: Babadagli T. 
Published: December 2007

Abstract
Depending on rock and oil type, lowered interfacial tension (IFT) by the addition of surfactant to brine may contribute to capillary imbibition recovery with the support of gravity drainage in naturally fractured reservoirs (NFR). This paper aims at identifying and analyzing the recovery mechanisms and performing up-scaling exercises for oil recovery from different rock types by the capillary (spontaneous) imbibition of surfactant solution.
Laboratory tests were performed using four different rock types that could possibly be the reservoir rock matrix of the NFRs (sandstone, limestone, dolomitic limestone and chalk). The sandstone sample was surface-coated to create a boundary condition causing only counter-current interaction. Wide variety of oils (light and heavy-crude oils, kerosene, and engine oil) was selected as the oleic phase. Different types (non-ionic and anionic) and concentrations of surfactants were used as the aqueous phase as well as the brine as a base case. The samples fully saturated with oil (Swi=0) were exposed to static capillary imbibition and the recovery was monitored against time. Some experiments on the chalks were repeated using pre-wet samples (Swi &gt; 0) to clarify the changes in the capillary imbibition characteristics of the rock.
The changes (positive or negative) in the recovery rate and ultimate recovery compared to the brine imbibition were evaluated for the rock, surfactant and oil types. It was observed, for some rock samples, that the imbibition recovery by surfactant solution was strictly controlled by the concentration of the surfactant. On the other hand, the difference in the recovery rate and ultimate recovery between high and low IFT could be due not only to change in the IFT but also the change in the wettability and adsorption, which might vary with the rock type. This was also analyzed using the shape of the curves that indicates the strength of the capillarity on the recovery and the interaction type, i.e., co- or counter-current.
In addition to the above-mentioned qualitative analysis, the recovery curves were evaluated for up-scaling. Existing dimensionless scaling groups were tested. The scaling exercise helped identify whether the recovery is driven by gravity or capillary forces and clarify the interaction type, i.e., co-or counter-current or both. The ultimate recoveries were correlated to the Inverse Bond Number using twenty-five cases covering different combinations of four rock types, four oil and four surfactant samples. It was shown that the inclusion of the wettability factor would make the correlation more universal.
In-Situ Diagnosis of Inflow Behavior in Horizontal Wells
Authors: Bui T. D. , Vicencio O. A. , Sinha S. , Kalita R. , Jalali Y. 
Published: December 2007

AbstractWe investigate the concept of inverting certain wellbore measurements acquired during the normal process of production to infer the distribution of inflow along horizontal wells traversing heterogeneous formations. We consider measurements that are in principle feasible with fiber-optic sensors. Besides distributed temperature-sensing systems that have an established deployment record, we also examine wellbore pressure sensing at multiple points, which is nascent technology. One outcome of our analysis is broad requirements of such systems, such that they can be used in diagnosis of flow problems relevant to horizontal wells. We investigate this problem by modeling techniques encompassing multiple physical phenomena in the coupled wellbore-reservoir media (flow, thermal, and compositional), and associated inversion techniques (pressure and flowrate). We confirm the informative character of multipoint flowing pressure for liquid influx detection, liquid-liquid discrimination (under certain conditions), and also establish magnitudes of temperature effect associated with influx of gas-liquid mixtures. Results indicate the problem of two-phase influx in horizontal wells can be reasonably resolved with the method proposed in this study. Further work, however, is required to refine certain aspects of the methodology. We briefly address the implication of this methodology with respect to conventional methods, i.e., production logging.
An Innovative Approach To Integrate Fracture, Well Test and Production Data into Reservoir Models
Authors: Bahar Asnul , Ates Harun , Al-Deeb Maged H. , Salem Salem E. , Badaam Hussein , Linthorst Steef , Kelkar Mohan 
Published: December 2007

AbstractThis paper presents an innovative approach to integrate fracture, well test and production data into the static description of a reservoir model as an input to the flow simulation. The approach has been successfully implemented into a field study of a giant naturally fractured carbonate reservoir in the Middle East. This study was part of a full field integrated reservoir characterization and flow simulation project.The main input available for this work includes matrix properties, fracture network, well test and production data. Stochastic models of matrix properties were generated using geostatistical methodology based on well logs, core, seismic data and geological interpretation. Fracture network was described in the reservoir as lineaments (fracture swarms) showing two major fracture trends. The network and its properties, i.e., fracture porosity and permeability, were generated by reconciling seismic, well logs, and dynamic data (well test and PLT).The challenge of the study is to integrate all the input in an efficient and practical way to produce a consistent model between static and dynamic data. As a result, it is expected to reduce the history matching effort. This challenge was solved by an innovative iterative procedure between the static and dynamic models.The static part consists of the calibration of model permeability to match the well test permeability. It is done by comparing their flow potentials, kh. In this analysis the dominant factor in controlling production at each well, either matrix or fracture, was determined. Based on the dominant factor, matrix or fracture permeability was modified accordingly. This way the changes in permeability are kept inline with the geological understanding of the field.The dynamic part was carried out through a full field flow simulation to integrate production data. The flow simulation at this stage was used to match production capacity, i.e. to determine whether the given permeability (matrix and fracture) distribution is enough to produce the fluid at the specified pressure during the producing period of the well. The iteration is stopped once a reasonable production capacity match is obtained. In general, a good match was achieved within 3–4 iterations. The generated reservoir description is expected to substantially reduce the effort required to obtain a good history match.
In-Situ Diagnosis of Formation Characteristics in Horizontal Wells
Authors: Cui H. , Dong Y. , Kalita R. , Sinha S. , Jalali Y. 
Published: December 2007

AbstractWe present a method of estimating the distribution of permeability along the length of a liner-completed horizontal well from measurements of well flowing pressure at multiple points along the path of flow in the wellbore. We do not model the deployment mechanism of the sensors, although in principle this can be achieved with stinger completions.The method applies to flow under constant-rate conditions and yields estimates of permeability along well trajectory in the principal directions normal to well path. Therefore, estimates of horizontal permeability perpendicular to well orientation and vertical permeability can be obtained for the gridblocks intersected by the well. Estimation accuracy, however, improves when the geometric mean of the normal permeabilities is obtained, as opposed to their individual values. This permeability group is what governs the influx into the wellbore. We neglect the effect of skin, but the method can be used to invert for a piecewise well index coefficient, that is proportional to the permeability group and inversely proportional to skin. Therefore, the method can generate the longitudinal profile of a parametric group that represents the quality of the formation and the integrity of completion.The quality of the inversion is governed by the spatial density of measurements, accuracy of measurements, knowledge of wellbore hydraulics, and knowledge of the relative permeability characteristics of the formation. We obtain fair estimation of wellbore-gridblock permeability distribution for a five-node pressure configuration in a 2000 ft horizontal well experiencing 60 psi pressure drop (10,000 STB/day), given realistic bands of uncertainty associated with the governing parameters, including measurement drift, and errors in liner roughness, and relative permeability exponent. Also, the inversion can be rendered insensitive to knowledge of the reservoir permeability field through a far-field scaling technique. Therefore, good estimates of the near-wellbore permeability profile can be obtained with highly uncertain knowledge of the reservoir permeability field. This is important as the technique can be applied not only to early-time but also late-time data. We illustrate the application of the multipoint pressure method through a series of examples and discuss its potential as an interventionless method of well diagnosis, for estimation of both flux and permeability distribution in high-angle completions.
Implementation of Pressure Maintenance in Seria Field Using Limited Entry Fractured Water Injection
Authors: Sommerauer Gerald , Petersen Russel 
Published: December 2007

Abstract
The Seria Field is the largest oil field in Negara Brunei Darussalam. It straddles the coastline of Brunei about 120 km west from the capital Bandar Seri Begawan.
This paper discusses the novel application of Limited Entry Fractured Water Injection in two reservoirs in the Seria field as part of a larger implementation of secondary recovery and future efforts to increase economic oil production and ultimate recovery in the Seria field.
In 1999 a Produced Water Re-Injection (PWRI) Project was launched in Brunei Shell Petroleum (BSP) to re-use the produced water for re-pressurizing some of the depleted reservoirs of the Seria field. After having screened more than 400 reservoirs, it was decided to implement the PWRI pressure maintenance scheme as a first phase in two reservoir blocks. The paper will describe the implementation of the two pressure maintenance projects focusing on the completion of the water injectors. In describing the project the authors address the advantages and disadvantages of fractured injection compared to matrix injection and it’s impact on required surface facilities. A pseudo-three dimensional fracture propagation simulator has been used to evaluate the optimum fracture design for the injection wells. The simulation results show the advantages of a multi-frac design like smaller fracture dimensions, earlier pressure support of all layers, superior profile control, lower capital costs, and increased cumulative injection potential. Various completion options for the water injectors have been reviewed and the selected limited entry fractured water injection design described. Closing the paper the author describe the monitoring and surveillance program for the conformance control and fracture containment.
The presented novel completion design has the potential to revolutionize the completion of water injectors and the application of PWRI in general for water flooding projects.
The presented novel PWRI completion design is in the implementation stage and first results are expected in 2004.
Laboratory Investigations of First Contact Miscible Wag Displacement: The Effects of Wag Ratio and Flow Rate
Authors: Al-Shuraiqi H. S. , Muggeridge A. H. , Grattoni C. A. 
Published: December 2007

Abstract
Miscible WAG injection has been implemented in a number of oil fields around the world and there are a number of numerical studies investigating the effect of rate, gravity, slug size and heterogeneity on WAG performance. However there are very few laboratory studies of WAG displacement efficiency reported in the literature.
In this paper we report the results from a series of well-characterised WAG displacements through glass bead-packs. The aim of these experiments was to investigate the impact of first contact miscible WAG injection on oil recoveryto clarify the physical processes during displacements.to provide benchmark data-sets to validate reservoir simulations.
The use of bead-packs rather than cores enabled us to observe visually, for the first time to our knowledge, the fluid interactions during each WAG experiment.
A series of secondary, miscible WAG displacements were conducted at WAG ratios of 1:1, 4:1 and 1:4. These were performed at a range of flow rates to investigate the influence of capillary number on recovery efficiency. Their behaviour was compared with that obtained from simple miscible injection and waterflooding.
We show that recovery efficiency is a function of rate as well as WAG ratio. We also find that the water-oil and the water-solvent relative permeabilities are not the same for the analogue fluids used. This is despite the fact that the oil and solvent are first contact miscible. If this is true for reservoir fluids then clearly it will affect the prediction of WAG recovery efficiency.
The Slug Suppression System in Operation
Authors: Kovalev K. , Cruickshank A. , Purvis J. 
Published: December 2007

Abstract
In a flowline/riser system large liquid slugs and surges can be formed by operational changes or due to the flow conditions and physical characteristics of the flowline. These liquid slugs and gas surges may result in large oil and gas production losses when they arrive at a production platform. Slugging may cause high-level trips in separators and lead to unstable operation of topside facilities. The S3® Slug Suppression System provides a reliable solution to the slugging problem.
In 2002 Dril-Quip (Europe) Ltd delivered the first two commercial S3 units to Shell UK Exploration and Production (Shell Expro). The first unit was designed for the Otter development (TotalFinaElf) in the North Sea and installed on the North Cormorant platform (13 km flowline, 12" riser diameter, 18 bara separator pressure). In October 2002 the unit was successfully commissioned and is presently operating. The second system has been installed on the Brent Charlie platform in the North Sea, and is used for the Penguins development (64 km flowline, 14" riser diameter, 35 bara separator pressure). The unit was commissioned in January 2003. The commissioning results prove that the S3 can control liquid slugs and gas surges. The operational data shows that the control strategy is robust, flexible and capable of operating within all flow regimes encountered in the flowline.
The S3 system consists of a small separator with dynamically controlled valves at the gas and liquid outlets. The system is placed just upstream of the production separator. Shell Global Solutions developed the system with advanced control algorithms over the past years. The new technology was successfully tested at a test rig in Amsterdam and during field trials at the Shell Expro Gannet Alpha platform [1]. Operation of the S3 system was also extensively simulated with the dynamic numerical tools Traflow and Olga2000 and compared to other slug mitigation methods. An exclusive license was granted to Dril-Quip (Europe) Ltd to manufacture and supply the S3. Based on the field experience with the system, the S3 has proven to control/mitigate slugging.
The Role of the Annular Gap in Expandable Sand Screen Completions
Authors: Heiland J. , Cook J. , Johnson A. , Jeffryes B. 
Published: December 2007

Abstract
When an expandable sand screen is installed, the gap between the outside of the screen and the rock can vary from zero upwards. The gap is influenced by the state of the hole after drilling, subsequent logging or completion operations, and the natures of the screen and expansion process. This paper describes experiments and modelling undertaken to help understand and clarify the impact of the gap on the short- and long-term integrity of the completion.
Experiments measuring hole closure showed that the presence of a screen always improved hole stability relative to that of the open hole; this benefit was reduced when there was a significant annular gap. This conclusion was supported by rock deformation modelling, which showed that for a screen with relatively low radial stiffness, a very small or zero gap was best, while a stiff screen could tolerate a slightly larger gap, up to a few millimeters. In both cases this is to allow mobilization of rock strength through yielding. Gaps larger than this allow the rock to break up, potentially leading to point-loading or erosion problems. Modelling of the transport of liquid and sand showed that a smaller gap reduces annulus liquid velocity, ultimately to the point where sand transport (and potential erosion) no longer occurs. It also identified conditions that could compromise the long-tem integrity of the screen, such as blocked screen sections or regions of enlarged gap, which generate persistent regions of concentrated flow through the screen wall, again potentially leading to erosion problems.
The experiments were carried out using a newly developed bistable sand screen1. This has been designed to conform as closely as possible to the borehole wall, and have a very low deployment force, but the conclusions are equally applicable to other types of screen.