bluuebunny/crossref_metadata_2025_split huggingface dataset:
Proactive Optimization of Oil Recovery in Multilateral Wells Using Real Time Production Data
Authors: Alghareeb Zeid M. , Horne Roland N. , Yuen Bevan B. , Shenawi Shamsuddin H. 
Published: October 2009

Abstract
Smart wells provide great potential to improve the recovery from hydrocarbon resources. Smart wells provide the ability to control uncertainties associated with reservoir heterogeneity. One example is to mitigate unexpected water production due to fractures and hence increase the ultimate recovery. This is achieved by selectively controlling production from multiple laterals. Due to subsurface communication between laterals that have different productivity indices, it is difficult in practice to optimize production from smart wells. The optimization of smart wells involves adjusting parameters including the settings of the downhole inflow control valves (ICV) that act as subsurface chokes.
This paper focused on the reservoir engineering aspects of finding the optimum ICV configuration that optimizes reservoir performance parameters such as recovery factor and net present value. Also, the work studied the effect of heterogeneity, mainly fractures, on the optimization process. This paper also proposes a technique to quantify the effect of fractures on the optimization process and to provide recommendations of further analysis.
Genetic algorithm (GA) was used as the main optimization engine to find the optimum ICV configuration. The GA was accompanied by a data library (proxy) to reduce the number of required simulation runs. A commercial reservoir simulator was used as the objective function evaluator that assesses the outcome of candidate ICV configurations.
Several examples are presented to show the improvement in reservoir performance made using the optimization process. These examples include a synthetic model, and a real onshore model. Various objective functions were optimized such as water cut, and net present value.
A Novel Approach to Identifying Refracturing Candidates and Executing Refracture Treatments in Multiple Zone Reservoirs
Authors: Barba Robert E. 
Published: October 2009

Abstract
Refracture candidate selection and treatment execution has always presented four main challenges to the industry when multiple pay zones are involved. The first challenge is determining the underlying cause of the poor production performance (poor reservoir quality, an ineffective original stimulation treatment, or both). The second challenge is the identification of the specific zones with significant remaining reserves that have been poorly stimulated. The third challenge is determining the current reservoir pressure in all of the prospective refracture candidate zones. The fourth major challenge is selectively stimulating the target zones in the wellbore when there are existing perforations above the target zones.
The first and second challenges are addressed using the "Completion Efficiency" (CE) or "Recovery Factor" (RF) techniques discussed in SPE 90483.1 These techniques use an integrated petrophysical, reservoir, and completion model to evaluate well and zone performance. The techniques has been employed on over 3000 zones to date in a wide variety of reservoirs with excellent results. The CE and RF analysis can be supplemented by rate-transient production decline analysis if adequate producing time has elapsed. The third challenge is addressed using selective zone buildup and/or injection tests to obtain reservoir pressure and permeability. The recommended technique uses a service rig and a low rate pump truck, tubing, packer, bridge plug, and a surface readout pressure gauge with downhole shutin. This technique has recently been employed on over 60 zones in the last two years in the Hugoton field in Kansas with excellent results. The fourth challenge is selectively isolating individual perforated intervals for the refracture treatments. The most efficient technique involves the use of openhole packer hardware set inside the cased hole. The openhole packer technology has been primarily deployed in horizontal openhole wellbores to date, however the hardware is readily adaptable to cased holes and has been used on a number of vertical cased holes to date (Table 1). The integration of these proven techniques (CE, RF, downhole shutin surface readout testing, and openhole packer hardware) provides the means to meet all of the main challenges of refracturing multiple zone wells. Field examples are provided to demonstrate the viability of the concept, and a methodology is proposed for "best practices" in the implementation of the techniques.
Lumping and Delumping for Integrated Compositional Modeling
Authors: Rastegar Reza , Jessen Kristian 
Published: October 2009

Abstract
Compositional reservoir simulation of gas injection processes is commonly performed with a reduced number of components to minimize computation time. However, in simulations of downstream processes, more detailed fluid descriptions are required to design and optimize separation processes. To connect up and down-stream processes, delumping approaches have been proposed to deconvolute the well/production streams from a reservoir simulator into a more detailed fluid description. The accuracy of delumping is closely tied to the lumping approach that is used to generate equation of state (EOS) input for the reservoir simulator. To this end, we have previously introduced a flow-based lumping scheme that includes information from the dynamics of a given displacement process into the grouping of detailed components. In this paper, we investigate the accuracy of the delumped production streams from various gas injection processes and compare results from different lumping schemes. We investigate the benefit of applying flow-based lumping schemes in the selection of pseudo-components for compositional reservoir simulation and find an improvement in terms of uniqueness and overall accuracy of the composition of the delumped well streams. Examples are provided from 3D displacement calculations of enhanced recovery by CO2 and separator gas injection for multicomponent reservoir fluids where a substantial amount of PVT data is available (CME, DDE, swelling test and slimtube MMP). Using a commercial reservoir simulator, the delumped compositions of the produced fluids are compared to detailed displacement calculations for three different lumping schemes and two different gas injection processes. We demonstrate that the proposed lumping/delumping strategy provides additional control of the predictive quality over currently available lumping/delumping approaches. In addition, the proposed workflow provides a unique answer to the question of how to lump a detailed fluid description for displacement calculations. A majority of oil fields currently under production as well as new developments are candidates for EOR processes such as gas floods. The approach presented in this paper are directly applicable to the study and design of such EOR processes an offers an improved workflow for integration of up and down-stream processes. This is, to our best knowledge, the first paper that presents a comparison of delumping results for flow-based lumping schemes in the context of gas injection processes in with emphasis on the accuracy of delumped production stream relative to other available lumping/delumping methods.
A Survey of Industry Models for Perforator Performance: Suggestions for Improvements
Authors: Behrmann L. , Grove B. , Walton I. , Zhan L. , Graham C. , Atwood D. , Harvey J. 
Published: October 2009

Abstract
For perforated natural completions, well productivity is dependent on the depth of the perforation tunnels extending beyond the drilling damage (all other things being equal). It is therefore important to accurately predict perforation depth at downhole conditions, in order to enable accurate prediction of well performance.
Most industry penetration models in use today are based largely on laboratory experiments conducted during the 1960's through the 1990's. Over the past decade or so, it has been observed that the accuracy of these models has not kept up with the true downhole performance of modern shaped charge perforators. Furthermore, different models can give quite different predictions of penetration performance of the same perforating system, in the same downhole environment.
To address this situation, the authors have recently conducted an extensive series of laboratory experiments, the results of which are enabling improved prediction of penetration performance in the field. Several hundred modern charges of different sizes have been shot into multiple rock types under simulated downhole stress conditions.
The primary conclusions of this work include: (1) historical penetration models tend to overpredict penetration at downhole conditions; (2) some industry models overpredict to a greater extent than others; (3) the discrepancy is partly due to the industry's continued reliance on performance into surface concrete targets. In addition, we observe that historical models tend to treat all charges equally, imposing the assumption that increased performance in one target (i.e. surface concrete) always and everywhere ensures increased performance in all targets (i.e. various stressed rocks). While this intuitive assumption is proven true as the "rule" on average, we find some significant exceptions. Although these exceptions complicate predictive modeling efforts, they do suggest opportunities to optimize charges for certain targets preferentially over others.
Our conclusions have led to ongoing work including (1) the development of improved penetration models, which rely exclusively on stressed rock, rather than unstressed concrete, performance; (2) the development of perforators optimized for downhole conditions, rather than for surface concrete.
Novel Enzyme Stabilizers for Applications at Extreme High Temperatures
Authors: Samuel Mathew , Mohsen Abdul Hameed , Ejan Aziz Bin , Ooi Yean Sang , Ashraf Shameed , Nasr-El-Din Hisham A. 
Published: October 2009

Abstract
Cleanup of drilling fluid filter cake in long horizontal and multilateral wells is a difficult task. Both mechanical and chemical means (acids, oxidizers, chelating agents, and enzymes) have been used in the field. However, these methods have serious limitations and can adversely affect well performance. Acids and oxidizers are very reactive, but are nonspecific. Enzymes can be used to degrade starch and xanthan polymers. The major limitation of enzymes is their inability to stay active at temperatures above 200°F.
The activity of enzymes at 207°F is less than 10% of their activity at 200°F. Previous studies to increase the stability enzymes were aimed at: (1) changing salinity, (2) changing the source of the enzymes, (3) using additives that alter the conformation of enzymes, or (4) chemically modifying the enzymes. These techniques did not maintain the activity of the enzymes above 200°F. For mudcake removal, enzymes have been used globally at higher temperatures, though their activity is known to be much less than 2%.
This paper examines the use of chemicals that work as a stabilizer for enzymes up to 250°F. Optimized concentrations of this stabilizer not only inhibit the coagulation of enzymes at these high temperatures, but also maintain the activity of enzymes at the high temperatures that are encountered in the oilfield. Laboratory studies on the stability, compatibility, and mudcake damage reversal were conducted with the stabilized enzyme formulation.
Experimental results indicated that the new proprietary enzyme stabilizer is very effective in eliminating the deactivation tendency of enzymes at high temperatures. Conventionally, enzymes coagulate above 140°F and char when exposed to temperatures above 200°F, but in the presence of the stabilizer, this precipitation and burning were not observed. When using an enzyme at high temperatures without the stabilizer, the burned residue accumulated on the surface resulting in a thin film that reduced the permeability of the cake even further. Core flood studies using the enzyme stabilizer showed that this film was not formed, which resulted in a cake with much higher retained permeability.
Improving the Process of Understanding Multiprobe Production Logging Tools From the Field to Final Answer
Authors: Frisch G. , Dorffer D. , Jung M. , Zett A. , Webster M. 
Published: October 2009

Abstract
The newest generation of production logging tools consists of multiple sensors in multiple locations around the wellbore that incorporate 12 resistivity and capacitance probes and six spinners. The capacitance array tool (CAT™) determines the water, oil, and gas holdup in the wellbore. The resistivity array tool (RAT™) determines the holdup of hydrocarbons and water. Likewise, the spinner array tool (SAT™) consists of six bowspring mounted micro-spinners that enable the measurement of the velocity profile. These new tools provide a detailed examination of the flowing fluids in all types of wells, including highly deviated and horizontal wellbores, that is not available with the traditional center sample tools because of the wellbore conditions, especially with fluid segregation. With these 30 measurements, a system of quality control and processing was developed to enable both experienced and non-experienced engineers to determine whether or not the data was correct and valid.
A quick analysis tool was developed to enable the field engineer and company representative to enter raw values from the two holdup devices and calibration values, and to determine the holdups from the two sensors. Similarly, entering the raw spinner counts, cable speed, and estimated spinner slopes into the quick analysis tool will provide an estimate of the velocity profile for the SAT spinners and the other spinners that are run. This quick analysis tool graphically shows the holdups and velocity in an easy-to-understand presentation for people who are not production logging (PL) experts.
After the raw data in the field is validated, a complete analysis is provided. This analysis includes horizontal, vertical, and 3D images of holdup and velocity profiles; continuous displays of flow profiles; and a complete flow analysis consisting of the split of oil, gas, and water rates at both downhole and surface conditions. This PL data can be presented in standard log formats, spreadsheets, and other methods as needed. This process can be modified by either the service company or customer. Several examples are provided that show the capabilities of the new logging tools and the interpretation method used to determine the results.
Residual Trapping of CO2 in Aquifers During the Counter-Current Flow
Authors: Nattwongasem D. , Jessen K. 
Published: October 2009

Abstract
The key challenge of CO2 sequestration projects is to ensure that selected formations will provide for long-term storage of CO2 without significant leakage. This is also the case for sequestration projects in saline aquifers, where substantial evidence must be provided that injected CO2 will remain in the target formation. However, the time-scales that characterize the immobilization of CO2 in aquifers are not yet fully understood. In this paper, we investigate the time scale for post-injection immobilization of CO2 and proposed a new dimensionless time scale that includes the contributions of both capillary pressure and gravity forces. The Bond number (NB) is included in the approach to capture the impact of the relevant driving forces. We use numerical calculations to study the interplay between capillary and gravity forces on the predicted evolution of a well-defined CO2 plume in an aquifer. Scaling analysis for 1D and 2D systems is presented for characterizing the plume behavior in different flow regimes as dictated by the relative magnitude of gravity and capillary forces (Bond numbers). A majority of the previous efforts on scaling analysis has focused on processes that are driven by capillary forces alone. However, for sequestration applications the impact of gravity force may be significant. We demonstrate that plume migration at constant Bond numbers may display very different characteristics as a consequence of phase mobilities. The results of our simulations and scaling analysis apply directly to the planning of CO2 sequestration projects and provide new guidelines for estimating the immobilization time of supercritical CO2 as well as the amount of CO2 that can potentially be trapped in a given aquifer.
Decline Curve Analysis for HP/HT Gas Wells: Theory and Applications
Authors: Ilk D. , Rushing J. A. , Blasingame T. A. 
Published: October 2009

Abstract
This work formalizes the Arps' D and b -parameters using a semi-analytical flow relation for a well produced at a constant bottomhole pressure in an HP/HT reservoir. The semi-analytical formulation is given in rate-time and rate-cumulative forms, and the definitions of the D and b-parameters are derived directly from the semi-analytical form.
The rationale for this work is the over-dependence that many analysts place on the Arps' D and b-formulations (i.e., the original hyperbolic rate-time model), tuned to specific (i.e., constant) values of the D and b-parameters. The purpose of this paper is to establish guidelines for reserve estimations and for production extrapolations in general. The relations developed in this work can be applied to a number of different HP/HT tight gas and shale gas field cases — in this work we validate our proposed procedure with a simulated example and we apply the methodology to a fractured gas well in an HP/HT reservoir. A comprehensive workflow is provided, as well as the relevant details/formulations of the analytical flow solution for HP/HT gas cases. We also provide decline curve plots/plotting functions to yield reserve estimates and production extrapolations.
Localization of Ensemble-Based Control Setting Updates for Production Optimization
Authors: Chen Yan , Oliver Dean S. 
Published: October 2009

Abstract
In the ensemble-based approach to production optimization (EnOpt), a steepest ascent direction is computed from an ensemble of controls to iteratively improve a set of control settings. The method was shown to work well in maximizing field NPV with an ensemble size of 104 on the Brugge SPE comparative test case for closed-loop optimization which had 84 controllable completion intervals (and total 3360 control variables), but performance of the method with smaller ensemble size or on larger problems might be difficult. Without regularization, the cross-covariance between control variables and the objective function is often likely to be dominated by spurious correlations. Because the update to the control variables is proportional to the covariance, spurious correlations will result in poor control settings.
We propose a localization method that updates the control setting to optimize the field production while reconciling information from each individual well. The proposed localization method reduces the effect of spurious correlations for improved performance. The Brugge test case is used as an example to show that with covariance localization much greater efficiency could be achieved through the use of a smaller ensemble.
Subsea Deployment of Instrumented Sand Screens in High-Rate Gas Wells
Authors: Somaschini G. , Lovell J. , Abdullah H. , Chariyev B. , Singh P. , Arachman F. 
Published: October 2009

Abstract
Arrays of miniaturized temperature sensors were deployed in the lower completion of six subsea wells in Southeast Asia. The novel system allowed the operator to perform batch completion of the wells. A mechanical fluid loss control device included in the lower completion and a temporary plug set above the lower completion after gravel packing enabled the operator to return later with the upper completion. Upon deploying the upper completion, acquisition was activated and cleanup data were transmitted, allowing the operator to monitor flow from individual reservoir zones. Subsequently, production data have been transmitted in real time to the operator headquarters from an offshore production platform, allowing continuous reservoir modeling.
Key to the communication success was the use of mating inductive couplers, with the female coupler just below the gravel-pack packer and the mating male coupler at the bottom of the upper completion. This coupler has been proven reliable in the presence of standard field operations. In some cases, there were multiple activations of the coupler, and all were successful.
Success of the overall system required that each interconnecting component and interface work as designed. For example, each temperature sensor was designed to land on a blank section of the sand-screen joint above the coupling. A special coupling clamp secured each sensor. The intersensor spacing was designed to be slightly longer than the longest anticipated sand screen. At each joint, a rig device applied a small S-shaped bend to the cable between the sensors. As the bend was formed, this shortened the intersensor spacing for precise onsite depth adjustment.
Similar attention to detail was expended on cables and rig handling. The cable allowed inline splices using a welded seal technique adapted to this specific deployment, the first field deployment of this technique. Significant effort was expended in weld development and testing, but nonetheless there were opportunities to continuously improve on process components such as cable handling and splice preparation.
The proven robustness of the system has led to alternative completion configurations such as monitoring the sandface of wells using electric submersible pumps for enhanced recovery.
Deepwater Developments: Successful Application of New Technology
Authors: Brandt Håvard , Isaksen Stefan , Friedemann Siri Helle 
Published: October 2009

Abstract
The oil and gas industry continues to explore deep and ultra-deep water development. However, these deep water developments introduce both technical and operational challenges not encountered in more shallow water developments. Further, the industry is continuously evaluating novel technologies, often with limited track records, to enhance the profitability and possible enable some of these technically challenging projects. While rigorous qualification programs often are introduced, there is significant uncertainty related to the performance of these systems.
The opportunities related to applying novel technology can be significant, however the uncertainty related to the reliability of these new systems may be difficult to assess. As a consequence the business impact and commercial performance of adopting these new systems is not fully understood. For conventional systems, Reliability, Availability, and Maintenance (RAM) analysis can successfully be applied to demonstrate the commercial performance of a given concept. A RAM model is a probabilistic simulation model which represents the expected performance of a system or a process. These models can be used to evaluate different development scenarios and assess the expected performance of alternative design options. These models do however require experience data which may be difficult to obtain or justify when applying novel technologies.
To better manage and understand the commercial impact of applying novel technologies, DNV has in cooperation with the industry and with the support from The Norwegian Research Council developed a guideline which combines Technology Qualification and Reliability and Performance Simulation. This process provides a better basis for decision support when evaluating novel technologies, and builds confidence in technology which truly has a strong business potential for a given project. This paper provides an outline of this new work process, and through case examples demonstrate the additional requirements on the technology qualification process required to establish confidence in reliability performance of the novel technology.