bluuebunny/crossref_metadata_2025 huggingface dataset:
Interactions Between Acids and Water-Swelling Elastomers
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Al-Humaidi A. S.
Published: September 2008

Achieving successful zonal isolation during well completion is critical to minimize early water production. Recently, oilswelling packers were used in various carbonate reservoirs, and currently water swelling packers are being investigated for potential field application. Considering future matrix acid treatments of wells completed with water swelling packers is part of this investigation. To the best of the author's knowledge there is no previous work done to fully investigate best practices in stimulating wells completed with water swelling packers.

An earlier investigation by Al-Yami et al.1 showed that water-swelling elastomers withstood pressures up to 5,000 psi at 190°F after placing the elastomers in brines with salinities up to 200,000 mg/l. CaCl2 completion fluids at 72 pcf, a common completion fluid, failed to swell the elastomers..

The present study investigates different acids to effectively stimulate wells completed with water swelling packers. Lab testing was done in 3 steps that included swelling the elastomers in low salinity aquifer water, soaking in various acids for 2 hours and finally immersing elastomers in the aquifer water to mimic resumption of water injection after conducting a matrix acid treatment.

Hydrochloric, formic acids and combinations of these two acids resulted in significant reduction in the volume of the swelled coupons. Immersing the coupons after acid exposure in water did not regain their original volume prior to soaking in these acids. Citric and lactic acids slightly reduced the volume of swelled packers from vendors II and III. The elastomers swelled again in water after exposure to these acids. Acetic acid showed the least effect on water swelling elastomers and their size was swelled again after immersing in water. The shape of coupons obtained from vendor III changed almost in all acids examined. The change in shape will definitely impact the ability of this type of packer to isolate various zones.
Simplified Modeling of Turbidite Channel Reservoirs
Authors: Alpak Faruk O. , Barton Mark D. , van der Vlugt Frans F. , Pirmez Carlos , Prather Bradford E. , Tennant Steven H.
Published: September 2008

Effective properties can represent fine-scale geologic heterogeneities in simple full-field reservoir models without having to explicitly model them. A comprehensive simulation study tests the sensitivity of dynamic connectivity in turbidite channel reservoirs to a large number of stratigraphic and engineering parameters. Simulations performed using geologically realistic sector models at multiple levels of stratigraphic resolution show that dynamic connectivity is governed by large-scale architectural parameters such as meander belt size, net-to-gross, and degree of depositional storey amalgamation; and stratigraphic parameters that describe the shale architecture at multiple scales, e.g. shale drape coverage and frequency of occurrence.

We demonstrate how to rapidly generate effective properties at multiple geologic scales, incorporating the effect of channel architecture and reservoir connectivity into simple dynamic models. Use of simple dynamic models in conjunction with effective properties, principally, geologically based pseudo-relative permeabilities, significantly accelerates the simulation workflow. We show that a statistical distribution of the recovery factor can be produced within hours instead of days by combined use of Monte Carlo simulation and a simple dynamic model with effective properties. Recovery factors estimated via our simplified modeling method agree well with observed recovery factor distributions of turbidite channel reservoirs with significant production history.
Optimal Value Testing – Moving From Vision to Reality
Authors: Elshahawi Hani , Hite Robert H. , Hows Melton P.
Published: September 2008

Over the past few years, there has been a vision that Optimal Value Testing (OVT) will replace conventional drill stem tests for in-situ measurement of dynamic reservoir properties such as permeability and drainage volume. This vision was that OVT would be safer, less costly, and friendlier to the environment, but the key impediment to OVT was the concern that the quality of the results might be inadequate for the difficult development decisions that we face.

Definitions of OVT vary but, in general, it may be defined as any testing method that yields fit-for-purpose results with the lowest cost and Health, Safety, and Environmental (HSE) impact. In more pragmatic terms, an OVT is any pressure transient test in which live hydrocarbons do not have to be produced directly to surface. Our OVT toolbox currently includes three types of well tests – wireline formation testing (WFT), closed system testing with cleanup and repeat surges, and injection testing. Our recent examples of closed system tests and wireline formation tests have proven to us that we can get comparable data quality to a conventional DST. Injection testing, aimed at determining drainage volume, is still relatively immature, as we have executed only one injection test to date. However, there has been considerable design work that makes us believe that this technology is also promising.

Our experiences with OVT over the past several years suggest that the wireline formation tester solution is the best answer in a large proportion of our cases. We will therefore focus in this paper on describing its strengths, weaknesses, and opportunities. Our applications of this technology are still evolving, and there are clearly more issues to resolve than with a conventional drill stem test. However, by drawing on our increasing breadth of experience, future value of information decisions about doing in-situ dynamic measurements will more often include this cheaper, safer, and more environmentally friendly option.
Shallow Penetration Particle-Gel System for Water and Gas Shutoff Applications
Authors: Vasquez Julio , Eoff Larry , Dalrymple Dwyann , van Eijden Jip
Published: September 2008

This paper presents the development of a new system for water and gas shutoff operations. This system combines a conformance sealant (based on an organically crosslinked polymer) with non-cement particulates. The particulates provide leakoff control, which leads to shallow matrix penetration of the sealant. This filtrate from the leakoff is thermally activated. After exposure to the bottomhole temperature of the well, it forms a three-dimensional gel structure that effectively seals off the targeted interval. This system can be considered an alternative to standard cement squeeze operations, casing leak repairs, sealing of thief zones, and perhaps many other wellbore operations.

The system can be bullheaded into the well allowing for easy placement and calculation of treatment volume. The limited and controlled leakoff into the matrix during the squeeze results in a controlled depth of invasion. Selective perforation of the oil zones re-establishes the desired hydrocarbon production from the targeted interval. The system can be easily washed out of the wellbore, as compared to cement, which must be drilled out. The temperature range of the particle-gel system is 70 to 350°F (21 to 177°C). To date, more than 54 jobs have been performed with this system. This paper presents results obtained from laboratory evaluations, the methodology of the job design, and limited case history information.
Samarang Pipeline-Replacement Project: Application of an Innovative Approach for Shallow-Water Pipeline Installation
Authors: Rashdi Khairil Raezwan , Sainal Muhamad Rashid , M Yusoff M Nabil
Published: September 2008

This paper presents the approach adopted in the replacement of ageing pipelines at offshore Sabah, Malaysia by PETRONAS Carigali Sdn. Bhd. (PCSB), the E&P arm of PETRONAS. Several options were explored to best deliver the project considering the installation difficulties were exacerbated by the congested field, ageing offshore structures, spaghetti pipeline networks, monsoon wind and presence of corals on the seabed. On top of these, the field's shallow water provides further complexity to the construction and installation works. The paper also shares the means engaged to mitigate the challenges and lessons learnt during the project's planning and executing stages.

Subsequent to the preventive inspection findings, a project was initiated in 2006 – as part of PCSB's commitment to rejuvenate ageing offshore facilities, sustaining the field's integrity and assuring reliability of supply. The Samarang pipeline replacement project was initiated to address these issues and espouse the integrated field development within its block. As a fast track project, the construction method engaged has to be sound and capable for expeditious work completion to avoid jeopardizing production. Through a thorough evaluation process, an innovative pipeline installation approach utilizing a shallow draft work barge was chosen for the project.

The project was completed with the successful installation of all four pipelines in December 2007. Despite many challenges, the project progressed smoothly without major setbacks. It was successfully completed ahead of schedule, within budget and recorded zero LTI and zero TRCF. The new construction method which requires assimilation of both the conventional and new approaches for offshore installation, has demonstrated its effectiveness hence proving the plausibility of the method for other projects with similar circumstances.

In the pursuit of sustaining and revitalizing old offshore facilities, pipeline replacements are inevitable to prolong intra and interfield operation flow of hydrocarbon. The unique and uncertain offshore environment, particularly at the shallow water areas introduces many installation challenges. Although proven methods are available, exploring a new approach to pipeline installation is essential to safely and effectively deliver projects with minimum costs. By selecting a suitable approach for pipeline installation, new networks of hydrocarbon flow facilities can be developed, thus allowing continuous production for decades to come.
Real Time Well Diagnostic Using Slick Line Fiber-Optic Distributed Temperature Sensors: West Venezuela Applications
Authors: Gonzalez Y. J. , Azuaje A. J. , Duarte T. , Sapon R. , Madariaga M. N. , Rubio E. A , Montoya C. , Martinez Santiago Maryvi , Castillo Saluzzo G. L , O'shaughnessy P. , Perez Padron M. A , Berbin A.
Published: September 2008

Conventional slick-line temperature surveys enable successive temperature measurements at pre-determined depth stations along the well-bore. This method has two major drawbacks. The wellbore fluid flow dynamics impact the temperature accuracy while the uncertainty in depth leads to erroneous conclusions on spatial temperature distribution along the wellbore. Remedial actions based on these temperature measurements do not always help optimize productivity or injectivity. To overcome these measurement uncertainties and correctly evaluate the gas-lift system performance for the oil producer wells or to identify temperatures anomalies, such as flow behind casing for water injection wells, continuous temperature measurements with time and depth are needed.

The slick-line fiber optics distributed temperature sensors technology presented in this paper measure simultaneous temperature traces along the well-bore with time. This is widely used in oil wells located at Maracaibo Lake, where approximately 95% of the wells are produced using gas-lift and also applied in La Concepcion water injection wells for wellbore integrity. There are technical papers on fiber-optic technology applications as a qualitative monitoring tool but very few case histories where slick-line is used as the method of fiber deployment.

This paper will describe eight success histories where fiber-optic sensors have been deployed using slick-line. These case studies are grouped as follows: Gas-Lift System Evaluation in which four wells were subject to analysis: Completion leakages detection in producers and injectors; Identification of water entry as well as channeling of water behind casing.

This paper will also demonstrate the application of this technology to implement production enhancement techniques. The use of this technology for operational flexibility, time saving and data quality will be compared to conventional temperature logging. In addition, it will show how environmental risks are eliminated by deploying fiber on slick-line for leak detection services.
Formation Powered Jet Pump Use at Kuparuk Field in Alaska
Authors: Peirce J. W. , Burd J. A. , Schwartz G. L. , Pugh T. S.
Published: September 2008

Formation powered jet pumps (FPJP) were pioneered for use in Kuparuk Field wells on the North Slope of Alaska. Unlike conventional surface powered jet pumps, these pumps are hydraulically powered by a prolific producing upper zone called the C sand to generate greater drawdown on a less productive lower zone called the A sand. Formation powered jet pumps increase oil rate from the A sand while reducing the water rate from the C sand.

Gas lift can be used in formation powered jet pump wells to further enhance drawdown on a well while jet pumping. Many formation powered jet pumps are being used in Kuparuk wells with gas lift to increase the drawdown applied to the A sand.

An overview of formation powered jet pumps used at Kuparuk Field is presented. Formation powered jet pumps could be beneficial in other multi-zone oil fields around the world to increase oil production rate, while reducing water production rate and lifting costs.
Corrosion Consequences of Nitrate/Nitrite Additions to Oilfield Brines
Authors: Martin Richard L.
Published: September 2008

Because nitrate ions are sometimes added to oilfield brines for bacterial control, a laboratory study was conducted to determine the possible influence of nitrate and nitrite ions on steel corrosion. Corrosion consequences were suspected due to the oxidizing potential of these ions and some oxidizing agents are known to promote accelerated corrosion.

Results of this study indicated that nitrate ions did not influence corrosion or its inhibition. However, nitrite ions sometimes enter these systems and they can be influential. Nitrite ions caused sour (contains H2S) oilfield brines to become more corrosive and compromised corrosion inhibor effectiveness in both sweet (no significant H2S) and sour systems.
New Test Method to Qualify Production Chemicals for Subsea Injection
Authors: Alapati R. , Sanford L. , Williams T. , Gao S.
Published: September 2008

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

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

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

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

The 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

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

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.
Petroleum Business Intelligence and Operational Analytics
Authors: Shimbo David
Published: September 2008

Petroleum executives and oilfield operations managers are making large capital investments and daily operational decisions with incomplete information, even though this data exists within the enterprise. This paper will show how to use business intelligence tools to make better business and operational decisions by integrating technical data from E&P applications, operational data from the oilfield and financial data from ERP systems.
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

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

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

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

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

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.
Alternatives to 25% Chrome for Water-Injection Tubing in Deep Water
Authors: Fitzgerald Aine , Groves Steve , Gosch Stuart , Morey Steve , Pattillo P. David , Piskurich Nick , Sathuvalli U. B.
Published: September 2008

This paper describes the material selection for tubing in water injection wells for deepwater applications. It details the qualification and deployment of an alternative to duplex corrosion resistant alloy (Duplex-CRA) tubing, including the testing work that was performed. Also described are the operational aspects of running the resulting product in several deepwater wells.

With the advance into expensive subsea wells, along with the use of produced water re-injection and the historical performance of de-oxygenation systems, most recent water injector designs for deepwater projects do not utilize carbon steel materials. The common materials are Duplex-CRAs, which are often an order of magnitude higher in price than carbon steel, and carry a significantly longer delivery time.

There are few alternatives to Duplex-CRAs. A common choice is glass reinforced epoxy (GRE) lined tubing, whose costs are similar in magnitude to carbon steel tubing and whose delivery time is significantly shorter.

GRE-lined tubing requires a set of rings and/or flares to be inserted at the length to length interface. Initially, the connection was modified to allow insertion of the rings/flares in a machined groove in the coupling. This was acceptable for many applications. However, for deeper water, higher pressure wells connection with better performance was required.

By employing a modified connection on GRE-lined tubing, BP successfully used it in shallower water injection wells. By 2003, the need was recognized for GRE application in deepwater injection wells. This would require qualification for the following further requirements Deep water tubing generally requires un-modified proprietary connections due to the loadingsSpar environments introduce fatigue loading and stresses on tubing that requires additional testingGRE tubing had not been run in production prior to injection conditions in deep waterEach GRE connection is commonly drift checked after make-up; this is not suitable for many deepwater operations.

The paper will detail the material selection for tubulars, the reasons for the product development and the final qualification testing. Installation experience of the product in several deepwater wells is described.

Deepwater water injection wells often cost more than producer wells. Cost is increasing as material prices continue to rise. On a project scope, the cost savings of non Duplex-CRA tubing is significant; thus the GRE manufacturer is now running the qualified product in many other deepwater projects for a variety of operators. As a result of this testing and qualification, GRE-lined tubulars are now being used for the majority of BP deepwater non HP HT water injection projects.
Successful Adaptation of a New-Generation Wireline Installation Capillary System for Downhole Chemical Injection on Anadarko's Subsea Ticonderoga Field
Authors: Cromb John , LaGrone Blake , Bolding Jeff , Lormand Percy
Published: September 2008

Asphaltene deposition can greatly impair production rates, and even with sound prevention and remediation measures, can still lead to a reduction in production rates or even well failure. An intervention to repair a subsea failure is often times more expensive than the original completion cost, and can greatly affect the overall project economics. The prevention of asphaltene with chemicals will work to a certain extent, but only from the chemical injection point upward. Remediation efforts such as the bullheading of chemicals will help to restore production to previous levels, but can cause complications in wells with sand control equipment.

Anadarko recently experienced a subsea completion failure due to excessive asphaltene deposition. Xylene was used to remediate the asphaltene, but the buildup continued below the injection point. Ultimately, a gravel pack failure occurred after a bullhead remediation effort. During the intervention, it was determined that the blockage in the wellbore region below the chemical injection point was the cause of the well failure.

A new methodology and hardware were incorporated into the sidetrack, which should eliminate bullhead treatments while still preventing asphaltene deposition from the bottom perforation to surface. Preventing a sidetrack or intervention is a huge monetary savings.

This paper will demonstrate the theory, hardware and application of new completion tools and methods which can prevent costly interventions or sidetracks. This system can also assist with scale, organic deposits, hydrate accumulations, corrosion, or liquid loading at or below the point of entry of hydrocarbons, which previously was not possible on subsea completions.
Empowering Young Professionals to Lead After "The Big Crew Change"
Authors: Gell Christi , Schilling Laura
Published: September 2008

During the last decade there has been an increase in discussion about "The Big Crew Change" and how to prepare the industry's young professionals (YPs) for this outflow of knowledge from organizations and how to recruit and retain new talent.

There is a growing body of evidence that demonstrates increasing employee engagement and commitment has distinct business performance advantages (Pfeffer 1998, Pollard 1996, Edmans 2007). However, this industry has not given much emphasis to empowering the young professionals themselves to take a greater responsibility in developing and shaping their own organizations.

The authors of this paper worked in the same building for more than a year but never met until a mutual friend from outside the company introduced them. The benefit of connecting with someone internally with similar industry experience became clear, and the idea for iMPACT, the company's young professionals organization, took shape. During the planning phases, clear themes for the group's purpose emerged. YPs wanted to know: How do you meet other young people at the company? How do you manage your career to grow in knowledge and responsibility? What kinds of services does the company deliver and what is the company strategy? The company's YPs were looking for a way to make a difference.

The purpose of the group is to foster networking and career development among young professionals who want to learn more about the company, develop their careers, and enhance the contributions they can make in their individual areas. The program encourages a mixture of technical and business focus while creating a venue to interact with senior leadership through a monthly speaker series and quarterly social networking events. iMPACT has become a retention tool for the company to identify up and coming leaders as well as provide leadership training to YPs. This paper aims to get YPs more involved in shaping their careers and their company's future. It is about a young professionals group created for young professionals by young professionals.
Effects of High Oil Viscosity on Drift Velocity for Upward Inclined Pipes
Authors: Gokcal B. , Al-Sarkhi A. S. , Sarica C.
Published: September 2008

The translational velocity, velocity of slug units, is one of the key closure relationships in two-phase flow mechanistic modeling. It is described as the summation of the maximum mixture velocity in the slug body and the drift velocity. The existing equation for the drift velocity is developed by using potential flow theory. Surface tension and viscosity are neglected. However, the drift velocity is expected to be affected with high oil viscosity. In this study, the effects of high oil viscosity on drift velocity for horizontal and upward inclined pipes are experimentally observed. The experiments are performed on a flow loop with a test section 50.8 mm ID for inclination angles of 0° to 90°. Water and viscous oil are used as test fluids. Liquid viscosities vary from 0.001 to 1.237 Pa·s. A new drift velocity model is proposed for high oil viscosity for horizontal and upward inclined pipes. The experimental results are used to evaluate the performances of proposed model for drift velocity. The calculated drift velocities are compared very well with the experimental results. The proposed model could be easily implemented into translational velocity equation. It improves the existing two-phase flow models in the development and maintenance of heavy oil fields
Finding the Continuum Scale in Highly Heterogeneous Rocks: Example of a Large Touching Vug Carbonate
Authors: Nair Narayan , Bryant Steven L. , Jennings James W.
Published: September 2008

Many of the world's oil fields and aquifers are found in carbonate strata. Some of these formations contain vugs or cavities several centimeters in size. Flow of fluids through such rocks depends strongly upon the spatial distribution and connectivity of the vugs. Enhanced oil recovery processes such as enriched gas drives and groundwater remediation efforts like soil venting operations depend on the amount of hydrodynamic dispersion of such rocks. Selecting a representative scale to measure permeability and dispersivity in such rocks can be crucial because the connected vug lengths can be longer than typical core diameters.

Large touching vug (centimeter-scale), Cretaceous carbonate rocks from an exposed rudist (caprinid) reef buildup at the Pipe Creek Outcrop in Central Texas were studied at three different scales. Single-phase airflow and gas-tracer experiments were conducted on 2.5 in. diameter by 5 in. long cores (core-scale) and 5-to 10-ft-radius well tests (field-scale). Zhang et al.(2005) studied a 10 in. diameter by 14 in. high sample (bench-scale). Vertical permeability in the bench-scale varied from 100 darcies to 10 md and in the core-scale averaged 2.5 darcies. The field-scale permeability was estimated to be 500 md from steady state airflow and pressure transient tests.

In the bench and core scales a connected path of vugs dominates flow and tracer concentration breakthrough profile. Tracer transport showed immediate breakthrough times and a long tail in the tracer concentrations characterized by multiple plateaus in concentrations. Neither flow nor tracer transport can be explained at these scales by the standard continuum equations (Darcy's law or 1D convection dispersion equation). However, interpreting field-scale measurements with standard continuum equations suggested that a strongly connected path of vugs did not extend past a few feet. In particular, the tracer experiment in the field scale can be modeled accurately using an equivalent homogeneous porous medium with a dispersivity of 0.5 ft. In our measurements, permeability decreased with scale, while vug connectivity and multi-scale effects associated with vug connectivity decreased with increasing scale. We concluded that approximately 5 ft could be considered the representative scale for the large-touching-vug carbonate rocks at the Pipe Creek Outcrop.