bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Test Method to Qualify Production Chemicals for Subsea Injection
Authors: Alapati R. , Sanford L. , Williams T. , Gao S. 
Published: September 2008

Abstract
The application of production chemicals for flow assurance issues entails pumping the chemical to injections points that are either downhole or at the subsea tree via umbilical tubes. The integrity of umbilicals throughout the life of a field is crucial for maximum recovery without any lost production expenses. The new test method qualifies production chemicals for subsea injection by evaluating their long-term stability at seafloor temperature and high pressure conditions to assure umbilical integrity is not compromised.
Current test methods for qualifying subsea injection chemicals involve testing at ambient temperature or pressure. A proper test method should incorporate testing at the injection pressures, which could be up to 10,000 psi and seafloor temperature. However, the product stability at both low temperature and high pressure conditions can change with time (i.e., in the case of extended shut-ins for hurricanes or other reasons). Currently, producers empty the production chemical in the umbilical tubes and replace it with solvent packages to ensure their integrity for long-term shutdowns. The length of umbilicals can range from 3 to 35 miles and their diameters can range from ¼ in. to 1 in. The volume of chemical wasted in flushing the umbilicals of long length and/or large diameter over a period of time can be expensive and unnecessary.
The new test method will include evaluating the chemical characterization, physical properties, particle-size analysis, and performance before and after testing. If no changes are observed the product will be qualified for subsea injection. Previous test methods have not evaluated the long-term stability of production chemicals at subsea conditions.
The unnecessary expenses of chemical wasted in flushing the umbilicals and lost production revenues could be avoided if there is satisfactory lab test data showing unchanged product quality at the injection conditions for long periods of time. This new test method gives confidence to the producers and operators regarding the integrity of the umbilicals, prevents lost production time, reduces the evacuation time of offshore facilities for hurricanes, and provides quicker restarts after extended shut-ins.
Importance of Predicted Cementing Temperatures for Critical HP/HT Casing Design: Guidelines and Case Studies
Authors: McSpadden Albert R. , Glover Simon 
Published: September 2008

Abstract
Estimation of drilling and cementing temperatures using standard models and simulation tools is essential for robust casing design of critical HPHT wells. Standard casing and tubular analysis defines loads in terms of changes in thermal, pressure and mechanical conditions from an initial installed state. Often, the casing initial temperature conditions are assumed to be prevailing geothermal undisturbed temperatures (UDT). This is typically considered a conservative assumption which simplifies the design process and avoids definition or verification of the relevant sequence of drilling and cementing operations. However, for critical HPHT wells where design margins can be narrow, it may be necessary to describe the initial physical conditions as accurately as possible and to incorporate them into the casing design analysis. In this paper, the general methodology of engineering based casing design is reviewed and practical guidelines are presented to suggest when extra effort to accurately model initial casing temperatures may be critical and why conventional assumptions may be nonconservative.
Because the current industry environment is placing significant demands on operator organizations and engineering staff, the time and effort required to gather data or to determine proper assumptions for detailed well design has to be justified. All other things being equal, simple worst-case assumptions which facilitate quick analysis and decision processes are favored over more detailed modeling.
However, with the wells being constructed today increasingly classified as critical HPHT wells, the need for thorough and realistic model-based casing design must be identified when it is required. The case studies considered in this work result from a review of a wide range of critical HPHT well designs. It is significant that some combinations and load conditions indicate that assuming undisturbed geothermal temperatures is not necessarily conservative. This can be related to constrained thermal expansion in cemented zones.
Predicting Source Rock Quality Using GR Wireline Response and Umaa vs. pmaa Crossplots in the Lewis Shale, Green River Basin, Wyoming
Authors: LaGesse Jenny , Hurley Neil 
Published: September 2008

Abstract
Evaluating source-rock quality using wireline logs is a practical and economic tool for reservoir characterization. Wireline data of the Lewis Shale in the Green River Basin, Wyoming was analyzed to determine if source-rock quality indicators could be found. Gamma-ray tool response to uranium was found to be a good predictor of total organic carbon (TOC) values. The viability of using Umaa vs. ρmaa crossplots as a method to evaluate source-rock quality is less certain, as TOC signatures are overwhelmed by host-rock mineralogy.
Intelligent Oil Field of the Future: Will the Future Be Too Late?
Authors: Rajan Surya , Krome Jon D. 
Published: September 2008

Abstract
The workforce transition from the graying, experienced generation to the incumbent crop of workers underscores the absence of many advances that were promised as part of the Smart Wells and collective Intelligent/Digital Oil Field of the Future (DOFF). As we prepare to hand over controls to the thumbs seasoned on Nintendo controls, we don't commonly find touchscreen controls, 3-D visualizations, automatic diagnostics and predictive analytics widely prevelant in the industry.
Environmental factors such as ubiquitous computing, networking, and communication have contributed to nurture a worker profile that is likely to exhibit a need for much more speed and openness. Incredibly adept at technology applications as compared to the outgoing workers, however, the same incumbent worker is going to be years behind on the experience scale. The average worker experience profile is going to see a dramatic drop in the next five to ten years.
Workforce effectiveness and sustenance gains renewed focus in the oil field's "Big Crew Change". In that context, the delayed promises of the DOFF become painfully evident. This study challenges the notion that current pace of DOFF implementations is aggressive enough to materially contribute to the industry's future.
Improved Production Profiling Using Thermal Balance and Statistical Modeling in the Pinedale Anticline of the US Rocky Mountains
Authors: Donovan G. , Dria D. , Ugueto G. , Gysen A. 
Published: September 2008

AbstractThe Pinedale anticline is located in the Green River Basin of Southwestern Wyoming, USA. The field is the largest tight gas discovery for the onshore region of the United States in the last twenty years (Robinson and Shanley 2004). Gas production is from very tight, stacked clastic reservoirs that are Upper Cretaceous in age, with productive intervals in excess of 6000 feet. The large productive intervals require multiple hydraulic fracture stages to complete.Time-lapsed production analyses are performed to optimize well spacing and to characterize the gas bearing reservoirs. Production logs are also run to determine the effectiveness of the hydraulic fracturing and to identify water entry points that may lead to premature completion failures. Typical wells produce relatively small amounts of water, usually less than 5 percent by volume.It is nearly impossible to detect such small watercuts with conventional methods of production analysis. However, a probabilistic production analysis method simultaneously modeling flowmeter and temperature can take advantage of the high contrast between the heat capacity of gas and water and therefore provide good estimates of the water and gas production profiles, even in small watercut wells.This paper describes the technique used to improve the production flow profiling, supporting its assertions with case study results.
Case Study: Restoring Sand-Prone Subsea Wells to Production
Authors: Vazir M. , Acosta L. G. 
Published: September 2008

Abstract
This paper provides a case study of an intervention effort which returned to production three wells that had been on extended shut in, two subsea and one dry tree, in a mature BP operated Gulf of Mexico deepwater field. The three wells involved in this operation had been shut in due to incidences of sand production. The production facility was not designed with any sand management capability such as hydrocyclones, sand jets, etc. Thus, historically, any incidence of sand production led to a well shut in. The objective of this intervention was to evaluate integrity of the completions and the remaining production potential of each of the wells.
As deepwater and subsea fields mature, intervention and surveillance options on subsea wells have to be explored and developed. Several operational challenges were faced during the planning and execution of this operation due to the sand prone nature of the wells combined with the subsea environment. They were carefully assessed and the risks were effectively managed in order to return all three wells to production.
High Impact Techniques and Technology Increase Ultimate Recovery in Tight Gas Formations
Authors: Contreras Jesus D. , Durst Doug G. , Harris Travis , Watson Don R. 
Published: September 2008

Abstract
Cost-effective development of tight gas reserves depends upon strategic application of advancing technologies. By employing efficient fracturing techniques with an appropriate multi-stage fracturing completion, operators can achieve higher initial gas rates, increased recovery rates and reduced completion costs. The completion process employs a single-trip multistage completion system which is driving the cost-effective exploitation of difficult reservoirs. Discussion will center upon project management strategies followed by some case history results and lessons learned.
This entire process described as a project management strategy for this paper could be summarized as follows:
Planning the plan: document what it is you intend to do Validating the plan: ensure that it is technically and economically sound Supporting the plan: obtain support of the people that make key decisions Executing the plan: ensure the plan is properly carried out Concluding the plan: capture results and present objective evidence of the results Planning responsibility: assign and be responsible for the plan changes and consequences
Project management strategy considers key factors associated with reserve estimates, selection of number of fractures, production behavior analysis, production forecast analysis, risk analysis, fracture design, and economic evaluation. Additional considerations are given to equipment and operational issues such as quantity and spacing of packers and sleeves. The completion stage involves techniques and procedures of the fracturing process. These planning and execution strategies achieve mechanical, volumetric and economic success, established by the efficiency of each fracture and total gas production rate when compared to initial evaluations.
The single trip multizone isolation completion fracturing system reduces rig time and cost for hydraulic fracturing services, accelerates production and improves reservoir drainage. When coupled with effective fracturing strategies and best practice procedures, the system provides improved production from tight gas reserves.
Using the Formation Breakdown Pressure Measured in Pre-frac Test to Predict Natural Fracture Swarms in Low Permeability Carbonate at the Wattenberg Field in the Denver-Julesburg Basin
Authors: Yang Yuanhai 
Published: September 2008

Abstract
Natural fracture swarms are usually a critical factor governing hydrocarbon production from the carbonate formation. In a low permeability carbonate reservoir at the Wattenberg field, the author has observed that natural fracture swarms are more likely to exist near such geology structure as fault. While faults can be easily identified by well logs when they are penetrated by well bore, it is almost impossible to describe faults when they are missed by the well bore. This paper presents a new method to predict faults and natural fracture swarms by analyzing the formation breakdown pressure recorded at pre-frac test in areas where faults are not encountered by well bore. Using this method, the author has successfully mapped the distribution of faults and natural fracture swarms in the Niobrara Formation at the Wattenberg field. This paper provides 1) the correlation between fault and the minimum horizontal stress; 2) the calculation of the minimum horizontal stress using pre-frac test; and 3) the fault description obtained by the minimum horizontal stress.
Using Prefrac Test Information to Predict and Avoid Screenout Associated with Slickwater Frac in Tight Gas Sands at the Wattenberg Field in the Denver-Julesburg Basin
Authors: Yang Yuanhai , Hu Guonong , Kremer Anne 
Published: September 2008

Abstract
Slick water hydraulic fracturing is becoming more attractive as more tight formations and economically marginal reservoirs are developed. However, its economic advantage can not cajole us to ignore sand screen-out problem largely caused by its poor sand carrying capability. By studying pressure declining characteristics of leak-off tests and the corresponding frac job results, the authors have successfully correlated the pressure declining gradient of leak-off tests with the likeliness of sand screen-out. This method has been effectively applied to predict the likeliness of sand screen-out at the beginning of frac jobs, and avoid sand screen-out during frac jobs.
A Practical Use of Shale Petrophysics for Stimulation Design Optimization: All Shale Plays Are Not Clones of the Barnett Shale
Authors: Rickman Rick , Mullen Mike , Petre Erik , Grieser Bill , Kundert Donald 
Published: September 2008

Abstract
The most common fallacy in the quest for the optimum stimulation treatment in shale plays across the country is to treat them all just like the Barnett Shale. There is no doubt that the Barnett Shale play in the Ft. Worth Basin is the "granddaddy" of shale plays and everyone wants their shale play to be "just like the Barnett Shale." The reality is that shale plays are similar to any other coalbed methane or tight sand play; each reservoir is unique and the stimulation and completion method should be determined based on its individual petrophysical attributes. The journey of selecting the completion style for an emerging shale play begins in the laboratory.
An understanding of the mechanical rock properties and mineralogy is essential to help understand how the shale reservoir should be completed. Actual measurements of absorption-desorption isotherm, kerogen type, and volume are also critical pieces of information needed to find productive shale reservoirs. With this type of data available, significant correlations can be drawn by integrating the wireline log data as a tool to estimate the geochemical analysis. Thus, the wireline log analysis, once calibrated with core measurements, is a very useful tool in extending the reservoir understanding and stimulation design as one moves away from the wellbore where actual lab data was measured. A recent study was conducted to review a laboratory database representing principal shale mineralogy and wireline log data from many of the major shale plays. The results of this study revealed some statistically significant correlations between the wireline log analysis and measured mineralogy, acid solubility, and capillary suction time test results for shale reservoirs. A method was also derived to calculate mechanical rock properties from mineralogy. Understanding mineralogy and fluid sensitivity, especially for shale reservoirs, is essential in optimizing the completion and stimulation treatment for the unique attributes of each shale play. The results of this study have been in petrophysical models driven by wireline logs that are common in the industry to classify the shale by lithofacies, brittleness, and to emulate the lab measurement of acid solubility and capillary suction time test. This is the first step in determining if a particular shale is a viable resource, and which stimulation method will provide a stimulation treatment development and design.
A systematic approach of validating the wireline log calculations with specialized core analysis and a little "tribal" knowledge can help move a play from concept to reality by minimizing the failures and shortening the learning cycle time associated with a commercially successful project.
Impact of Pore Volume Compressibility on Recovery from Depletion Drive & Miscible Gas Injection in South Oman
Authors: Haynes Byron , Abdelmawla Ahmed , Stromberg Simon 
Published: September 2008

Abstract
Rock Pore Volume Compressibility (PVC) data can be misinterpreted during the early life of reservoir development due to the fact that there are minimal amounts of this data acquired during early reservoir life. This data is typically obtained from uniaxial or hydrostatic tests using conventional core acquired during the appraisal phase of the reservoir. This article presents a case study from a cluster of reservoirs, in Southern Oman that highlights the importance of using PVC to determine reserves associated with both the primary depletion and miscible gas injection. The cluster is being developed in a phased approach. The key objective of each phase is to gather data from the different reservoirs to assess if a miscible gas injection project would be feasible. Permanent downhole pressure gauges have been utilized to monitor reservoir performance from the depletion phase and to aid in the forecasting of oil recovery for the miscible gas injection projects. The reservoir pressure in one of the reservoirs producing in the depletion phase has declined faster than expected and can be attributable to either lower than expected oil in place volume or a lower the expected PVC. Obviously, having lower oil volumes in place would greatly impact the economics of a miscible gasflood development. Therefore, renewed focus on proper evaluation of the PVC from the latest emerging core data from appraisal wells in a this reservoir has indicated that although the originally assumed PVC was within the uncertainty range, it was at the high range of the data and some of the measured data was skewing the average. A new look at the material balance and simulation results verified that PVC and not a reduction in OOIP was the root cause of the difference in performance estimates and the observed reservoir performance. By using a new lower average PVC, the observed reservoir pressure is found to be consistent with new material balance and reservoir simulation results. This approach has clearly, provided vital information to underpin the recoverable reserves associated with the miscible gas injection.
Multi-Scale Data Integration in Characterizing and Modeling A Deep-Water Turbidite Reservoir
Authors: Ruvo Livio , Doyle James , Cozzi Mauro , Riva Simone , Scaglioni Paolo , Serafini Giuseppe 
Published: September 2008

Abstract
Information from cores and wireline logs, processed according to different methodologies, were integrated to provide a consistent facies classification, petrophysical characterization and 3D geological model of a deep-water turbidite reservoir in the Gulf of Mexico.
A number of sedimentological facies (sed-facies), either heterolithics or single-lithology, were first identified on cores and used for generating a conceptual depositional model of the reservoir. At the same time, the conventional wireline log recordings from both cored and uncored wells were processed using a multivariate statistical technique (cluster analysis) to provide a Net-to-Gross (or Vshale)-based log-facies classification. The relationship between sed-facies and log-facies is not straightforward, as some of the latter include different amounts of different sed-facies, either heterolithics or not.
The petrophysical characterization of the log-facies was carried out using a Process-Oriented Modeling approach. Realistic fine-scale, 3D digital models of the different sed-facies were generated. These models were populated at the lamina scale using the statistics of porosity measurements from a selected subset of the core plugs and the statistics of permeability measurements from a mini-permeameter, both parameters having been overburden-corrected in advance. Next, the fine-scale 3D models of the sed-facies were stacked according to their observed amount in each log-facies, and several porosity and permeability grids for each log-facies were stochastically generated. Eventually, the 3D log-facies models were analytically and numerically upscaled to respectively provide effective porosity and permeability statistics for use in the property modeling phase of the 3D geological model of the reservoir.
This workflow has the great advantage of allowing the use of data of types acquired at different scales (mini-permeameter, core plugs and wireline logs) in a consistent manner with respect to their volumes of investigation, and also allows for honoring the conceptual sedimentological model of the reservoir.