bluuebunny/crossref_metadata_2025_split huggingface dataset:
Challenges in Integrated Operations Centers
Authors: Landgren K. , Sood S. 
Published: December 2007

Abstract
Oil and Gas companies increasingly need environments that support real time E&P business processes, by linking well site information, applications, and experts with operational managers (decision makers) in one place, where daily operational parameters are viewed, decisions are made, and decisions are acted upon. Most companies believe that making decisions in real time while leveraging global resources and infrastructure will help improve their productivity from mature fields, while reducing costs.
Project team members are often collocated to ensure open communication and planning. However, E&P activities often take place in remote and hostile parts of the world, where it may not be possible or economical to deliver all the required resources and personnel. Global operations frequently require that operations centers be "virtualized" so the team members can be globally dispersed. Reliable and secure information flow is the key to ensuring success in the oilfield of the future.
Creating and supporting such integrated operations centers presents significant challenges in process, networking, security, hardware, and software infrastructure. For example, end-to-end real-time solutions require remote connectivity and "first mile" technology.
Successful creation of integrated operations centers requires clear definitions of the business processes to be supported and the infrastructure technologies needed to support them.
This paper discusses some of the special challenges faced in the upstream oil and gas domain, with examples of how some of the challenges have been met.
Beyond Temperature Sensors: Increased Efficiency in Mapping Flood Paths
Authors: Montgomery J. , Kofoed V. , Rollins P. 
Published: December 2007

Abstract
This paper will introduce a new procedure for mapping the flow paths of the steam, water and polymer floods frequently used in residual oil extraction. The procedure entails the strategic placement of electrodes within the designated oil reservoir. When the field is flooded, the electrodes charge the liquid with a low voltage, low amperage, audio-frequency electrical current. The current creates a distinctive magnetic field that represents the location and character of the flow occurring between the electrodes. This unique magnetic field is identified and surveyed from the surface using a highly sensitive receiver. This procedure can pinpoint the location of blockages and other problems more quickly and inexpensively than traditional methods, which typically rely on the intrusive placement of temperature sensors.
This procedure has been tested in a number of mature oil fields, including one near Bakersfield, California. In this case, the electrodes were placed in test wells that were specially designed to facilitate a charging of water vapor at various horizons. After the reservoir was flooded with high pressure steam, the mapping apparatus was able to take stratified readings of the magnetic fields created by the charged electrodes.
The procedure quickly identified a previously unknown subsurface structure that was effectively blocking the steam flow from reaching the intended solidified crude. The test thus established the new procedure's ability to map steam flows with greater speed and cost efficiency than traditional methods. The resultant maps were determined to be of equal or superior accuracy to those generated by the placement of temperature sensors.
One of the oil industry's most pressing tasks is to increase the yield from fields already under development. Such improved recovery methods hold significant advantages for both investors and the environment. Flooding is a proven method of extending reservoir productionlife. By providing a quick, efficient and accurate map of those flow paths, this new geophysical procedure represents an important forward step in the quest to teach "old reservoirs new tricks."
A Novel Approach for Analyzing the Dispersion Transport in Radial Coordinates
Authors: Garrouch A. A. , Guedouar L. , Al-Dousari M. M. 
Published: December 2007

Abstract
The finite-control volume technique is used to solve the radial convection-dispersion differential equation. In the dispersion model presented, the dispersion coefficient is dependent on both velocity and diffusion coefficient. The solution allows analyzing the dispersion transport of a slug in a steady radial flow from an injection well fully penetrating a homogeneous reservoir of uniform thickness and finite arial extent. Results show that the dispersive mixing zone does not necessarily grow in proportion with the square root of time for all times, unlike for the linear displacement. Results reveal a typical minimum of the dispersive mixing zone with time for radial displacement. It appears that at some radial distance close to the wellbore, the dimensionless mixing zone decreases with the square root of time since there is an accumulation of the miscible slug in this particular space domain. However, when the dissolution of the slug starts taking effect particularly at large distances away from the injection point, the mixing zone begins to increase with increasing square root of time.
Our solution of the convection-dispersion equation in radial coordinates allows to estimate the optimum slug size for miscible displacement projects in hydrocarbon reservoirs. This in return allows to estimate the total amount of solvent needed to maintain miscibility conditions at the displacement front in the bulk of the reservoir, leading to better reservoir management and to a more adequate economic forecast of EOR processes.
Drilling with Casing: Prospects and Limitations
Authors: Gupta A. K. 
Published: December 2007

Abstract
Drilling with Casing is a new technology used for simultaneously drilling and casing a well where the casing is used to transmit mechanical and hydraulic energy to the bit, instead of using a conventional drill-string.
The fundamental value of Drilling with Casing lies in improving drilling efficiency by eliminating flat spots in the drilling curve. It will eliminate the use of drill pipe, significantly reduce tripping times and reduce time lost due to unscheduled events such as reaming, fishing and taking kicks while tripping.
This technology utilizes a top drive to rotate the casing and uses a combination of traditional components such as standard oil field casing, bits, mud motors, MWD/LWD tools, as well as some newly developed components that allow drilling of most hole sizes from any drilling unit, with the ability to recover the drilling assembly using wireline. Since these tools are run and retrieved inside casing, they are protected from the harsh downhole environment while in transit. Casing drilling drill collars can also be used to add stability and to provide better fatigue resistance to the drill string.
This paper will describe the physical components and operational aspects of the drilling with casing system and its benefits over conventional drilling system. The anticipated results of drilling with casing are discussed and specific conclusions include in 20-30% reduction in the time required to drill wells from spud to rig release and up to 30% savings in well cost with improved reservoir productivity.
A New Scaleup Approach for Nonpattern Field Development Under Water or WAG Injection
Authors: Jhaveri B. S. 
Published: December 2007

Abstract
Full-field simulations have been successfully used to model reservoir development scenarios under water or WAG injection. When a reservoir is developed with regular patterns, reservoir engineers often build a type pattern model (TPM) and perform detailed, mechanistic, fully compositional simulation studies to understand displacement mechanisms. Simulation results from these mechanistic TPM studies are then scaled to full field to help design, develop, and manage the field waterflood or WAG injection projects. For a field developed with regular patterns, the scaleup of TPM results to the full field is quite straight forward; requiring identification and simulation of several different pattern types, followed by volumetric scaleup with tank models. However, when a field is developed with no regular patterns because of reservoir geology or other reasons, it is not clear how to apply the scaleup approach described above.
This paper presents a novel approach that uses simulation results from 2D (two dimensional) mechanistic models in conjunction with a full-field 3D waterflood study to describe the nonpattern field in a number of injector-producer segments. The approach also specifies the segment's initial pore volume (hydrocarbons and water), the injector, producer allocation factors, and recovery curves appropriate for the field development. For waterflood, the recovery curve is waterflood efficiency vs. cumulative water injected. For WAG floods, the additional recovery curve is EOR (oil incremental to waterflood) efficiency vs. cumulative solvent injected. Once the segment description with appropriate parameters is complete, it is straight forward to apply the tank model based scaleup approach to predict the full-field waterflood or WAG behavior. The paper presents the development and application of the new approach using example of a satellite field located on the North Slope of Alaska for a miscible WAG project.
Application and Development of Chemical-Based Conformance Control Treatments in China Oil Fields
Authors: Liu Y. , Bai B. , Shuler P. J. 
Published: December 2007

AbstractChina represents the largest user of chemical-based conformance control treatments and a series of technologies have been successfully developed and deployed in recent years. This paper will provide a review of current status of the application and development of chemical-based conformance control treatments in China.This paper first summarizes types and development history of conformance control treatments. Then a series of technology information for conformance control is introduced, including reservoir evaluation and testing, conformance control agents, decision-making technology of well selection, operation design and evaluation methods of application results. This paper also addresses the theories and applications of some promising combination technologies of chemical based conformance treatment and another EOR/IOR process, including the combination technology of surfactant and water shutoff, profile control and mini-type surfactant flooding, acid treatment and profile control treatment.Finally, this paper summarizes the problems and challenges that mature Chinese water flooded oilfields are facing. Based on recent well tests, tracer testing and interpretation, and previous water control treatment experience it appears that channels or high permeability streaks have been widely common in mature water flooded oilfields. Some research directions and promising technologies are suggested.
Investigation and Field Evaluation of a Foamed Viscoelastic Surfactant Diversion Fluid Applied During Coiled-Tubing Matrix-Acid Treatment
Authors: Nasr-El-Din H. A. , Chesson J. B. , Cawiezel K. E. , De Vine C. S. 
Published: December 2007

Abstract
When designing an acid treatment, the engineer often faces the question of what diversion method will be the most effective yet least damaging to the formation. Previous work has been published about evaluation methods, and conceptually diversion theory seems straightforward, but detailed post-job analysis and treatment optimization is often forgotten, especially when post-job production results meet or exceed expectation. Once a particular diverter is selected, the next question often is how much is required? If too small of volume is used, then treatment diversion will not be achieved. If too large of volume is used, then cleanup times and the risk of permanent damage increases.
Viscoelastic surfactants have recently become a popular additive for diversion pills, based on their polymer-free chemistry. Various formulations, including foam, have been successfully applied in acid stimulation treatments, but little post-job analysis has been published. Viscoelastic fluid properties vary over a pH range during acid spending on the formation and when foamed, determination of bottomhole properties is further complicated.
A tube viscometer and parallel core flow cells were utilized to determine the rheological properties and diversion effectiveness of various formulations of foamed viscoelastic surfactant at bottomhole conditions. An optimum formulation was determined, and this fluid was then applied and evaluated in a field application. A down-hole memory gauge was run during a coiled tubing acid treatment, and delta pressure changes were evaluated to determine the diversion effect.
A New Approach for Dynamic Optimization of Waterflooding Problems
Authors: Lorentzen R. J. , Berg A. M. , Nævdal G. , Vefring E. H. 
Published: December 2007

Abstract
Technological advances have resulted in use of smart wells, which are typically equipped with remotely operated downhole chokes. We present an approach for controlling these chokes so that the water flooding is optimized. The optimization problem is done by maximizing either total cumulative oil production or net present value.
The new methodology presented here avoids the limitations related to using optimal control as no adjoint equations are needed and the model equations are treated as a "black box".
In the new approach the ensemble Kalman filter is used as an optimization routine, and the methodology is compared to the Partial Enumeration Method.
We demonstrate the methodologies on a simple synthetic reservoir with five layers of different permeabilities. The conclusions from this work are that the ensemble Kalman filter approach is working robustly, and the results are in agreement with, or superior to, the results obtained with the Partial Enumeration Method and a reference solution.
A Multivendor Data-Exchange Format To Support Digital Oilfields
Authors: Weltevrede B. C. , Foreman R. , Morneau R. , Rugland B. , Booth J. E. , De Vries S. , Little T. , Ormerod L. , Doniger A. 
Published: December 2007

Abstract
Over the past decade the rapid evolution of Information Technology has enabled oil companies to much more effectively exploit hydrocarbon reserves than was possible up to now. These technologies all rely on an extensive set of instrumentation and controls.
The expected benefits of this novel approach to oilfield management are very high, but can only be harvested by means of an appropriate IT infrastructure and data exchange protocols.
PRODML (PRODuction xML) is a proposed data exchange mechanism which will facilitate the integration between software tools that are used in combination to turn raw production data into control actions.
PRODML intends to be an industry standard XML-based exchange format for production data. The scope of the first version of PRODML will be determined by what can reliably be delivered in a one year period.
This first version will support data exchange between applications in the office domain with emphasis on near-real time optimisation. In this context, near-real time optimisation is defined as optimisation that can be achieved by making changes in the existing production configuration that can be effectuated within one day.
The overall approach follows the successful example of the WITSML project, which established a similar set of specifications for the drilling domain.
PRODML was initiated jointly by BP, Chevron, ExxonMobil, Shell and Statoil in early 2005.
The initiative has since been joined by Halliburton, Invensys, OSIsoft, Petex, Schlumberger, Sense-Intellifield, Tietoenator and Weatherford, and is now in the process of developing the standard. POSC has agreed to take over stewardship of the effort once work on the first version has been completed and to foster further developments.
The paper represents the work of the entire team.
Rolling Anchor System
Authors: Bakke M. , Berg G. M. 
Published: December 2007

Abstract
The service industry continually strives to improve well service technology and help ensure that those developments can ultimately be deployed economically
The Rolling Anchor System (RAS) is designed to allow the use of Coiled Tubing (CT) in high torque operations where otherwise snubbing or conventional work over operations would be required.
The Rolling Anchor is designed to isolate the reactive torque generated by a motor from the work string, while at the same time allowing reciprocal movement of the bottom hole assembly (BHA). The Anchor is hydraulically activated by the pressure drop through the lower BHA (motor, mill etc.).
The Rolling Anchor System is patented in Norway, the USA and in the UK with Patent Pending status in several other countries.
This paper will provide a detailed overview of the tool’s design and discuss testing the tool has undergone to qualify it for service in various applications.
Utilizing Compositional Simulation for Material Balance and Bottomhole Pressure Calculations in CO2 WAG Floods
Authors: Kelly T. R. 
Published: December 2007

Abstract
In the current environment, carbon dioxide (CO2) flooding is gaining popularity as an enhanced oil recovery (EOR) technique worldwide. Despite this popularity, the complex phase behavior as well as reservoir and operational phenomena associated with CO2 flooding have dramatic effects on sweep efficiency, material balance calculations, and overall reservoir management. A technique for modeling the phase behavior of CO2 in injection wells was developed to address difficulties in material balance methods. Additionally, modification of the Cullender and Smith method of calculating bottom hole pressure (BHP) is proposed. The Peng Robinson equation of state is incorporated into the Cullender-Smith method to accurately predict CO2 phase behavior throughout the wellbore.
This technique uses the gas composition, temperature, and pressure from each injection well to calculate the volume factor at surface; additionally these parameters are used along with the wellbore configuration to determine BHP. This method greatly reduces errors in material balance calculations caused by using static rather than dynamic volume factors. Using this technique helps to maintain a constant BHP which facilitates volume-balanced injection cycles. In addition to injection rate, BHP targets can be set on continuous CO2 or water-alternating-gas (WAG) injectors such that it may be possible to establish and maintain a uniform flood front in patterns, no matter what fluid is being injected. In other words, the effects of reservoir heterogeneity, viscous fingering, and unfavorable mobility ratios are reduced by maintaining a constant BHP. A reliable knowledge of BHP is helpful in preventing injection above the formation parting pressure.
Modeling of Multilateral and Maximum Reservoir-Contact Wells in Heterogeneous Porous Media
Authors: Yang Y. , Deo M. D. 
Published: December 2007

Abstract
Maximum reservoir contact and multilateral wells offer more efficient production capabilities for certain classes of oil and gas reservoirs. These wells can be configured to have maximum contact with reservoir production zones. This is particularly important for highly compartmentalized, heavy oil, and off-shore reservoirs.
In computer modeling of reservoir production, traditional well models can only represent wells in directions that are parallel to the simulation grid which is usually not the case for maximum reservoir contact wells. An accurate well model that can effectively represent maximum reservoir contact and multilateral wells is necessary.
Current state of the art numerical well model for complex wells uses Green's function to compute the production index for each finite-difference block. The advantage of this approach is that the calculated production index fits naturally into the current finite-difference method used. The disadvantages of this method are such that it only partially accounts for heterogeneity, it is based on slightly-compressible single-phase flow and it sometimes generates negative production indices.
A novel line-well model for complex wells is proposed and studied. The line-well model places wells on the edges of computational blocks instead of centers as in traditional well models. This approach offers a physically meaningful yet simple way to compute production index for each individual segments of a complex well. This configuration also insures the proper handling of heterogeneity around wells. The line-well approach also allows easy implementation in both finite-difference and finite-element methods.
Verification of this well model for a traditional well arrangement with a commercial finite-difference simulator shows excellent agreement. Case studies show the efficiency and effectiveness of this well model in modeling reservoirs with multilateral wells.
Estimation of Relative Permeability from Displacement Pressure Data
Authors: Barroeta R. G. , Thompson L. G. 
Published: December 2007

Abstract
The solution of the inverse problem to estimate oil-water relative permeabilities, or history matching, has been widely used in the oil industry for many years. Usually, in this procedure, the production behavior, i.e., observed oil and water flow rates and pressure data versus time, is modeled and matched using a numerical regression process where the model relative permeabilities are modified until an acceptable solution is obtained. In some cases, only the production data versus time (without corresponding pressure data) are used to obtain the model relative permeability curves. To our knowledge, there have been very few instances where researchers attempted to use only pressure versus time data from core flood experiments (without the corresponding fractional flow) to estimate relative permeability curves.
In the laboratory environment, the pressure drop across a core during a displacement test can be determined with extraordinary precision - much more accurately than fractional flow data measurements. Since pressure measurements can be obtained easily, accurately and inexpensively, the number of data points collected during the experiment could be significantly increased, and also, data measured before breakthrough could be included. Based on this, a method has been developed to determine relative permeabilities through the solution of the inverse problem (numerical regression), by modeling, through the Buckley-Leverett procedure, the observed pressure versus time data only, and dismissing the recovery measurements. This approach significantly reduces the cost and time required to perform displacement experiments.
The results of the new technique, using power law representations for water relative permeability and oil relative permeability, are compared with relative permeability curves obtained using the standard history matching technique (finite difference simulator) and with relative permeability curves obtained using the standard unsteady state laboratory procedure (JBN). It is shown that there are only minor differences in the results, both from the point of view of the generated relative permeability curves and the estimated fractional recoveries, when the new approach is compared with the standard history matching procedure. Thus, the new method represents a viable and economically attractive procedure for determining relative permeability curves from laboratory displacement experiments.