bluuebunny/crossref_metadata_2025 huggingface dataset:
Extending the life of an ageing offshore facility
Authors: Hudson Brian G
Published: February 2011

This paper will describe, supported by examples and case studies, a structured and holistic methodology to support the extension of the life of an offshore platform or onshore terminal beyond that indicated by original design philosophy. The approach identifies the key asset reliability, integrity, vulnerability and process safety risks that need to be addressed to allow an asset to be operated beyond its design life. This methodology captures the generally accepted key issues that arise in operating assets at or beyond design life, including; corrosion, obsolescence of equipment, change in design duties, change in oil or gas properties or production profiles etc. It also considers the impact of other less obvious key issues, such as people competence, availability of historic information, maintenance practices, outsourcing, use of 3rd parties and ownership of corporate knowledge.

This methodology and has been applied to extending the life of the offshore oil and gas platforms in the UK, Danish and Norwegian shelf of the North Sea. In Norway it is a requirement to gain consent from the regulatory body prior to extending the life of a platform or field beyond original design. In the UK, the regulatory body sees such an extension in life as a significant and material change to the "Safety Case" and is in process of introducing Ageing & Life Extension Inspection Programme (KP4), to determine the extent to which asset integrity risks associated with ageing & life extension are being managed effectively by duty holders. In other parts of the world the shareholders, legislators and other stakeholders require assurance on the reliability and integrity of the asset.

In addition to identifying the programme of activities that operators need to carry out to extend and continue to maintain the asset life, the approach also provides a profile of CAPEX and OPEX expenditure through to the end of field.

With the volatile oil price and ageing profile of existing offshore platforms, the ability for operators and prospective investors to run assets beyond the original design life, whether for the short, medium or long term and still maintaining high standards of HSE and Integrity Management, is of paramount importance and forms a key part of any strategy to manage current and future business risk.
Gas Well Deliquification
Authors: Hearn William
Published: February 2011

Many gas wells cease producing economically long before their reservoirs have depleted and artificial lift applications for removing liquids from gas wells around the world are becoming more and more important.

Proper application of artificial lift technology to a loaded up gas well can be one of the most profitable ventures that a company undertakes in its overall investment opportunity portfolio. The dollars invested relative to the dollars returned, the rapid payout, and the generally low risk to reward nature of their spend is expected to continue to propel rapid expansion of Gas Well Deliquification Technologies into the fore seeable future.

This presentation will illuminate the importance of gas well deliquification technologies for the future. It will cover the basic fundamentals of the gas well liquid loading phenomena and provide a brief introduction to the Turner and Coleman equations used for critical velocity calculations. With these basic concepts covered, the presentation will then present a brief overview of the four most commonly applied artificial lift techniques used for deliquifying a gas well; reciprocating rod lift, foamer injection, plunger lift and gas lift. In conclusion, a logical artificial lift application selection process for gas well deliquification called the "Unloading Selector" will be introduced.
DO we need a Culture Change to Win Everyone’s Heart & Mind
Authors: Al Muflehi Mohamed , Macwan Nancy
Published: February 2011

Manuscript

During the last few years, it was realized that people get hurt because of their unsafe behaviors or improper attitudes and as attitudes are difficult to change and difficult to measure, behavior was our target to proffer the solution which is mainly to identify unsafe behaviour that leads to accidents and modify it or equally spot good behaviour and enforce it.

Therefore and in order to reduce accidents and improve safety performance, introducing an advanced behavioral safety audit program (BSA) on behavioral approach as a technique of working upstream of accident was introduced in Abu Dhabi Marine Operating Company (ADMA-OPCO).

Behavioral Safety Audit (BSA) program has two fundamental principles, it focuses on behavior rather than attitude and it stresses encouragement rather than punishment. The implementation of this program had a huge impact by encouraging a safe HSE culture. BSA“focuses on what people do, analyzes why they do it, and then applies a strategy to improve what people do”. To be successful the program must include all employees from the Chief Eexecutive Officer to the technical staff. To achieve changes in behavior a change in policy, procedures and/or systems most assuredly will also need some change. Those changes cannot be done without buy-in and support from all involved in making those decisions.
Modification of Existing Offshore Process Facilities (Engineering, Projects & Contracting: - Execution of Brown Field Projects)
Authors: Gopikrishnan M , Awda Hisham , Sherif Abdulla , Srinivasa Raja , Kotrappa Murugendrappa , Gupta Madan , Ismail Sherif , Telepurath Sunil , ZWSC Maintenance Team _ , Worley Parsons Team _
Published: February 2011

Background

Zakum West Super Complex: Abu Dhabi Marine Operating Company (ADMA OPCO) operates the offshore oil and gas producing facility at Zakum West Super Complex (ZWSC) and Zakum Central Super Complex (ZCSC). The crude produced from Lower Zakum field is processed at ZWSC and ZCSC.

ADMA OPCO approved a development scheme for Lower Zakum Thamama IV and Thamama V to maintain a sustainable oil production capacity of 425 MSTBPD (annual average).To achieve this production target, ADMA OPCO have selected the option of adding new well slots on the existing WHTs. These WHTs will be modified, as a part of a separate project, to accommodate additional wells.

At present, ZCSC CSP / PP facility is undergoing de-mothballing and ZWSC CSP / RP / NRP facility has been upgraded as a part of various ongoing projects including ZWSC CSP De-bottlenecking Project. Further to implementation of these projects, ZWSC CSP facility is able to handle 350 MSTBPD peak oil production (325 MSTBPD annual average). In order to handle additional 100 MSTBPD oil production (total corresponding to 460 MSTBPD peak oil production) from Thamama IV and Thamama V, some more modifications for ZCSC and ZWSC facility will be necessary.

Considering the above, ADMA OPCO had conducted a process study for ZWSC & ZCSC facilities covering various options with the objective of allowing operation for circa 100 MSTBPD additional oil production.

As a consequence of Process Study findings, ZCSC De-Mothballing Project was initiated by ADMA OPCO. Similarly, ADMA OPCO decided to carry out FEED (Front End Engineering Design) for modifications required on ZWSC platform.
First Worldwide Horizontal Run and Eastern Hemisphere Application of an Expandable Reamer and Stabilizer BHA on Troll Field, Norway
Authors: Evans Hugh D. , Ulvedal Lydia E.
Published: February 2011

This paper provides a case study review of the deployment of new reamer technology to the Troll field and the resultant performance improvement.

For the past several years expandable, concentric reamers have been used to drill the 12 1/4-in. x 13 1/2-in. landing section of multilateral production wells on the Troll field in the North Sea. Drilling with a pilot bit and reamer through this interval, which includes interbedded sands and hard calcites, is extremely challenging; the consequences are potentially destructive drilling vibrations, sub-optimal performance and significant drilling inefficiencies.

The operator invited the service company to run its recently developed expandable reamer and expandable stabilizer to determine the benefits of this new technology. The thorough design of the reamer ensures that it remains closed until triggered, opens on command, reams an in-gauge hole, then closes and comes out of the hole properly. The reamer benefits from a reduced number of seals and moving parts and an optimised cutter layout. The innovative expandable stabilizer was developed to provide full, rather than partial, stabilization above the activated reamer in the reamed hole. Typically when a stabilizer is placed above an expandable reamer it is constrained by pass-through size and therefore less effective. The expandable reamer and stabilizer combination ensures that the bottomhole assembly (BHA) is fully stabilized, with an optimal size stabilizer.

This is the first worldwide landing / horizontal application drilled with these tools and the first run in the Eastern Hemisphere. The only previous experience with the technology was on test runs at the service company's test facility in Oklahoma and drilling in the Gulf of Mexico (GoM.) The Troll 12 1/4-in. x 13 1/2-in. landing section was drilled to section total depth (TD) in one run, with both the expandable reamer and expandable stabilizer working as planned and with minimal vibrations and tool wear. The 9 5/8-in. x 10 3/4-in. liner was subsequently run smoothly to TD. The success of this run highlights the benefit of combining an expandable stabilizer with a concentric expandable reamer. The lower vibrations and improved drilling efficiency make this a preferred configuration for subsequent applications.

The paper describes the engineering design and testing practices used, the modelling capability and the performance results of the first run and three other runs that comprise the testing programme on Troll.
Innovative Subsea Cooling Reduces Risk in Subsea Pipelines
Authors: Azouz Amr
Published: February 2011

ADMA-OPCO Engineering Division has recently innovated a Subsea Cooling Scheme capable of rapidly cooling down the temperature of operating fluids even in high flow gas pipelines. The scheme can be inherent into the original pipeline design without adding any additional costs resulting in the elimination/ reduction of various major risks whenever temperature is a main contributor. The higher the temperature, the higher are the cost savings and risk eliminations/ reductions. ADMA-OPCO has already applied the scheme into the detailed design of one of its major gas projects resulting in extensive savings in addition to other numerous benefits relevant to risk reduction and operations.

The subject paper describes the challenging process of identifying all risks associated with the first application of its kind. Not less challenging was the technical management of those identified risks to acceptable levels.

In addition to above, the paper describes the concept of subsea cooling and what are the associated extensive benefits to the pipeline system design and operations. Moreover, how to technically adopt such scheme to various needs utilizing the knowledge captured from the pilot application in ADMA-OPCO Project.

The paper also briefly describes typical constraints which would limit the application of such a scheme.

Finally, the paper highlights potential future developments relevant to the concept/ scheme and what is deemed required for widening its applicability.
Opportunities for Energy Efficiency Enhancements in the Oil and Gas Industry using Waste Heat Powered Absorption Chillers
Authors: Popli Sahil , Rodgers Peter , Eveloy Valerie , AL Hashimi Saleh , Radermacher Reinhard , Hwang Yunho
Published: February 2011

The oil and gas industry is under increasing pressure to improve the efficiency of its energy-intensive oil and gas processing operations, through improved energy utilization and waste heat recovery. This paper explores the use of waste heat-powered absorption cooling to boost the efficiency of natural gas (NG) processing, enhance hydrocarbon recovery and reduce utility cost in a NG plant. A thermodynamic analysis of a gas turbine waste heat-powered double-effect H2O-LiBr absorption chiller in an integrated NG plant is presented. It is found that waste heat recuperated from the turbine exhaust gases could be used to provide enhanced process cooling capacity to the NG plant through absorption cooling. The results suggest that a double-effect LiBr absorption chiller utilizing 34.6 MW of gas turbine exhaust heat could provide 45 MW of cooling at 5 °C. This could save approximately 9 MW of electric energy required by a typical compression chiller while providing an equivalent amount of cooling.
Strategies for Evaluation of the CO2 Miscible Flooding Process
Authors: Gao P. , Towler B. , Pan G
Published: February 2011

Field experience has shown that CO2 miscible flooding is an effective means to improve oil recovery. To evaluate whether a CO2 miscible flood is suitable for a given field and the development of the optimal design requires considerable investigation and tests prior to a field-scale implementation. This paper proffers some guidelines for using a CO2 miscible flooding operation so that the feasibility and profit can be optimized. The guidelines for evaluating whether a CO2 miscible flood is suitable for a given field are developed and the procedure for a full implementation is summarized. These guidelines cover primary screening, laboratory measurements, reservoir simulation, economic analysis, pilot testing, and field application. Detailed methods also are presented for the optimization, well pattern and spacing preparation, and slug and injection process design. The work offers reservoir engineers a reference for decision-making in CO2 miscible flooding.
Study of Friction Reducers for Recycled Stimulation Fluids in Environmentally Sensitive Regions
Authors: Aften Carl W.
Published: February 2011

Recent studies involving the measurement of friction reducer performance with a variety of brines typical of flow back/recycled stimulation waters of the North Eastern United States have indicated a clear differentiation by specific product type. The friction reducer variances specifically studied were: product charge, charge type, charge distribution reflective of polymerization, molecular weight, inverse emulsion surfactant packages, and manipulation of the internal or external phases.

Increasing environmental regulatory pressure in geographic regions sensitive to water use, stimulation flow back discharge, and an increasing need for recycled water, the Marcellus gas play for example, have created a greater demand for higher performing additives in fluid systems used for oil/gas well fracturing. One additive that is greatly influenced by brine characteristic and water quality is the friction reducer. Increasing the ionic strength as well as multivalent cation content of the water typically limits the type of friction reducer used to obtain optimum performance. Standard anionic friction reducers do not perform well in many of these recycled waters as the friction reducer’s ultimate performance is decreased, but also the rate of inversion is retarded and the potential for formation damage is increased.

When compared to standard friction reducers, the ultimate friction reduction of the best of the series studied achieved nearly twice the friction reduction, approaching Virk’s theoretical limit, and had an inversion rate nearly four times as rapid as a standard friction reducer. The dosages of the friction reducer were from 0.25 to 1.00 gallons per thousand gallons of treatment fluid. These friction reducers were tested in a variety of brines in a 10 gallon capacity friction loop through a ½ inch pipe at a Newtonian Reynolds number of 150,000. The data was collected every second during a 10 minute run with 6 specific performance criteria used to rank the candidates.

This study demonstrates it is possible to provide a friction reducer that works well in brine content typical to stimulation fluids that contain a majority of flow back water from previous well treatments. This would allow well service companies to provide quality stimulation fluids of greater brine content and also minimize fluid disposal volumes and affiliated costs. Chemical additives such as these are needed in regions where both water quality and quantity are concerns.
Barnett Shale: A Resource Play - Locally Random and Regionally Complex
Authors: Hale Brent W.
Published: February 2011

The Barnett Shale play in north central Texas has 14,382 wells which were originally primarily vertical wells. Currently 68% of the wells are horizontal wells. This Barnett Shale has significant changes in performance and quality as produced fluid type changes, as the depth changes, and as the thickness changes. Completion type is known to have a significant impact on well productivity. This review relates peak month rate to reservoir performance. The peak month rate is shown to be impacted in a predictable manner by horizontal wellbore length, by lateral azimuth, by completion depth, by gross pay interval, and by type of fluid being produced, which ranges from dry gas to oil. A P10/P90 ratio is used to measure the relative uncertainty in performance for the various subsets of the Barnett Shale reviewed.
The Effect of Pressure and Temperature on Brine-CO2 Relative Permeability and IFT at Reservoir Conditions
Authors: Liu Ning , Ghorpade Sachin , Harris Lee , Li Liangxiong , Grigg Reid , Lee Robert
Published: February 2011

Geologic sequestration of CO2 in deep saline aquifers has emerged as a technology with the greatest potential to economically sequester large quantities of CO2 from a wide range of industrial operations for greenhouse gas mitigation. The displacement characteristics of CO2 injected into deep saline aquifers are essential because they control both the migration of CO2 and the available pore space in the reservoir at irreducible saturation conditions. This paper presents the steady-state brine-CO2 relative permeability measurements in a sandstone core under CO2 flooding conditions versus pressure and temperature. The results indicate a strong correlation between pressure and the endpoint relative permeability to CO2. As the pressure increased from 1200 psi to 2600 psi, the end point relative permeability to CO2 increased from 32.4% to 46.8%. Temperature was found not to strongly affect the relative permeability, although the end point relative permeability to CO2 decreased with temperature increase from 31.05°C to 38°C. This paper also describes the effects of pressure and temperature on the interfacial tension (IFT) between CO2 and brine. The IFT was observed to decrease as pressure increased and increase as temperature increased. These data will provide useful information to evaluation, analysis, and optimization of CO2 sequestration in deep saline aquifers.
Making the Case for Shale Clay Stabilization
Authors: Carman Paul S. , Lant Kimberly S.
Published: February 2011

Shale gas plays are very active and there is little time available for the practicing engineer to spend on well studies that would describe the effectiveness of particular treatment chemical additives. Each shale play has variations within its own lithotypes and mineralogy suite, not to mention that shales differ from each other individually in key mineralogical and geomechanical measures. These differences in lithologies, mineralogies and geomechanics within the formation itself should be evaluated to develop a minimum standard application for fields. Particular attention should be paid to the clays as they are the most ion-influenced components of the rock. Clay minerals in shales seem to be misunderstood in some cases. Lithologies and clay mineral suites that should require minimal temporary and/or permanent clay protection are being disproportionately treated with expensive clay protection chemicals.

By evaluating the geologic age, formation temperature, mineralogy, Brinell hardness, and Capillary Suction Time test results one can draw some conclusions about clay responses to fluid exposure. Using the results of these analyses in conjunction with previous experience and other independent well data can give reasonable information to make proper fluid selections in shale reservoir completions.

The results presented in this study show very different responses for several different clay protection chemistries when tested on shales of known clay content. Although most of the shales studied here contain very little, if any, swelling clay, certain additives yielded a questionable response. The study presents both test results and laboratory evaluation techniques for selection of clay protection chemical additives and economical considerations in shale reservoir completions.
Characterization and Simulation of ECBM: History Matching of Forecasting CO2 Sequestration in Marshal County, West Virginia.
Authors: Calderon C. E. , Mohaghegh S. D. , Bromhal G.
Published: February 2011

Uncertainties of CO2 injection-sequestration in a CBM is driven by the complex process of gas desorption-controlled mechanism attributed to the natural characteristics of CBM and to the impact of the wells engaged in the reservoir. This work presents the reservoir characterization and simulation process focused on natural gas production and subsequent CO2 injection into an unmineable coal seam in the Marshall Country West Virginia. Two coal seams (Pittsburgh and Upper Freeport) are the subject of this pilot CO2 sequestration project. Methane is produced from both coal seams; however CO2 is injected only in the Upper Freeport which includes four wells. The shallower Pittsburgh coal is used to observe and detect any possible leakage.

The objective is to build a reservoir simulation model that is capable of matching the methane production history and forecast field potential capacity for CO2 injection and sequestration. Although injection has taken place in two reasonably close wells, these wells exhibit different production and injection behavior.

A commercial simulator is used for modeling. Three realizations of the reservoir were built and history matched base on different Langmuir isotherms. The model which leads to a better approximation of the actual injection profile is selected for further analysis. Upper Freeport formation characteristics, its CO2 storage capacity and CO2 distribution in the reservoir are presented in this article. The model can be used to define safety margins for the maximum bottom-hole pressure during injection.
Case Studies in the Application of Pad Design Drilling in the Marcellus Shale
Authors: Poedjono Benny , Zabaldano John , Shevchenko Irina , Jamerson Christopher , Kuntz Robert , Ashbaugh James
Published: February 2011

The current focus of many US land drilling programs is on major unconventional gas shale plays. In this paper, the authors will discuss the challenges posed by and effective solutions developed for wells drilled in one of these plays: the Marcellus Shale. In response to the economic, real-estate, water disposal, and regulatory challenges the Marcellus Shale presents, multiwell pads have become a common approach. Historically, the Marcellus and Appalachian Basin has been developed using inexpensive, vertical wells drilled using the latest technologies and techniques. While some of these options are still viable, changing conditions make proper surveying and anticollision monitoring imperative. The pad design, surveying, preplanning, and execution of successful multiwell pad drilling require extensive collaboration between service providers and operators, a process that will be addressed in this paper.
Performance of the Hydraulically Fractured Horizontal Wells in Low Permeability Formation
Authors: Belyadi A. , Aminian K. , Ameri S. , Boston A. Light-Foot
Published: February 2011

This paper summarizes the results of the modeling studies to determine the production performance of multiply fractured horizontal well completed in tight sand or Shale formations. A commercial reservoir simulator was utilized to model both single and a dual porosity reservoir with multiple layers. The results were utilized to investigate the flow regimes for horizontal wells with one or multi-stages of hydraulic fracturing stimulation. The impact of reservoir and fracture parameters on the flow regimes and the production performance was also investigated.
Impact of Carbon Dioxide Sequestration in Gas/Condensate Reservoirs
Authors: Ramharack R. , Aminian K. , Ameri S.
Published: February 2011

Sequestration of CO2 in depleted gas condensate reservoir has several advantages including enhanced hydrocarbon liquid recovery. Depleted gas condensate reservoirs have 13 times higher capacity than saline aquifers for CO2 storage. The injection of CO2 vaporizes the liquid that has been trapped in gas condensate reservoirs during the depletion process. This results in an increase in the pore space for storage purposes as well as enhanced economics due to additional liquid recovery. The improvements in liquid recovery will depend on purity of CO2. A compositional reservoir simulator was utilized in this study to investigate the impact of reservoir characteristics including permeability, porosity, heterogeneity, pressure, and temperature on CO2 distribution and interaction with hydrocarbons in the gas/condensate reservoirs. The results have utilized to study CO2 storage and improved liquid recovery.
Optimization of a Solid-Acid Precursor for Self-Destructing Filter Cake
Authors: Rostami Ameneh , Nasr-El-Din A.
Published: February 2011

This paper presents a technology for water-based drilling fluid that is weighted with calcium carbonate. This technology has both functions of drilling and completion fluids and can reach to the total depth of MRC wells. It creates a filter cake that prevents fluid leak off and formation damage during the drilling process, but readily cleans up the filter cake over time. This technology is based on the use of an ester, in a solid form, which hydrolyzes and produces an organic acid. The latter will dissolve calcium carbonate particles that are used as a weighting material in water-based drilling fluids. Polylactic acid (PLA) particles were used in the present study to generate lactic acid.

Experiments were conducted to find an optimum particle size of the solid ester and calcium carbonate particles that should be selected as a compromise between those that are optimal for fluid loss control or filter cake formation and those that are optimal for self-destruction at the desired time and rate. Other set of experiments were conducted to determine the temperature and soaking time required for the solid ester to hydrolyze and for the resulting acid to dissolve calcium carbonate particles.

All experiments showed that in a controllable-condition of temperature, acid concentration, and particle size the clean up efficiency exceeded 70%. The optimum particle size was found to be 50 µm calcium carbonate and 150 µm PLA. The optimum temperature was 230°F for running experiments due to high filter cake removal efficiency, low filtrate volume and not having returned mud high viscosity problems. Enough soaking time is needed for PLA to be hydrolyzed and for the acid to remove the filter cake (20 hours).
Analysis of Stress and Pore Pressure in Naturally Fractured Shale Formations: A Finite Element Based Chemo-Thermo-Poroplastic Model
Authors: Roshan Hamid , Rahman Sheik S.
Published: February 2011

Most shale formations are naturally fractured and wellbore instability is a common problem in these formations. In previous wellbore stability analysis shale formations have been treated as a homogeneous rock which underestimates drilling mud parameters. The aim of this paper is to study the transient change in pore pressure and stress state around a wellbore drilled in a chemically active fractured shale formation. For this purpose a finite element model for coupled chemo-thermo-poro-plasticity is developed. A discrete fracture network is generated based on an object-based hybrid neuro-stochastic simulation. Permeability tensors of the fracture network were calculated by using boundary element method which is based on periodic boundary conditions around the grid block and interface boundary conditions around the fracture edges.

In order to solve the plasticity problem a single step backward Euler algorithm including a yield surface correction scheme is used to integrate the plastic stress-strain relation and an initial stress method is employed to solve the non-linearity of the plastic equation. Super convergent patch recovery is used to accurately evaluate the time dependent stress tensor. The solute advection and thermal convection are also considered due to presence of the natural fracture system.

From the results of this study it was revealed that the pore pressure decreases around the wellbore due to the backflow of chemical and thermal osmosis. When drilling through fractured shale formations, however, the decrease in pore pressure is lower than that of intact shale formations which is mainly due to solute advection through the fractures. Also it was found that the effective radial and tangential stresses can reach yield strength of the rock in presence of fracture system thus casusing serious instability problems. It is more likely to form a plastic zone near the wellbore wall in the presence of natural fracture than otherwise. In this study the formation of plastic zone leads to wellbore failure by exfoliation.
Marcellus Net Fracturing Pressure Analysis
Authors: Gottschling John C.
Published: February 2011

An investigation of the net fracturing pressure of multiple stage HZ Marcellus wells was undertaken to give some indication about the Marcellus differences or similarities in 3 areas of the Appalachian basin. References were cited to support the theory that an increase of the net fracturing pressure is an indicator of fracture complexity. Data used for analysis was taken from treatment reports containing surface rate, pressure and sand concentration. The theory behind the analysis of fracturing pressure and the methodology used were presented and supported with literature references. Calculations to determine the components of the Surface Treating Pressure to Net Pressure relation were done making assumptions about the friction pressure and closure pressure. Compilation of the net pressure data from Areas 1, 2, and 3 was presented and discussed with explanations offered for differences seen between these areas as well as the value of net pressure as an analysis tool.
Innovative Simulation Techniques to History Match Horizontal Wells in Shale Gas Reservoirs
Authors: Fazelipour Waleed
Published: February 2011

Shale-gas plays are the current rage in the US energy industry and have started a new era for hydrocarbon production, worldwide. Drilling is expanding; shale-gas wells are not hard to drill, but difficult to complete. The challenge is to release gas from rock as impermeable as concrete. Horizontal drilling and stimulation are enabling technologies that make development of unconventional shale-formations economically viable. Rocks around wellbores must be fractured before wells can produce significantly. Multistage hydraulic-fracturing treatments create complex conductive networks, represented by stimulated reservoir volumes (SRV) which have been effectively contacted and contribute to higher production profiles.

Reservoir characterization/modeling and simulation offer the best techniques to evaluate well performance and estimate the ultimate recovery. History matching or replicating past well behavior is the first, crucial step in simulation and is very difficult; however, as complex as it is, history matching, which calibrates the simulation-model is required to generate convincing forecasts. Main challenges to simulate past/future production include accurately describing the SRV, its geometry and position; fractures intensities and characterizing matrix/fracture attributes.

This paper presents innovative techniques, which previously were impossible to perform, in order to history-match horizontal wellbores by focusing on the mentioned matrix/fracture challenges to sensitize the complex growth and attributes of hydraulic-fractures. The techniques played an important role in understanding the stimulated shale volumes. Key conclusions of achievements include the capability to generate more reliable forecasts/predictions that are highly critical if it is aimed to understand well performance and optimize its productivity.

This research has led to a game-changing methodology for the global E&P industry that enables operators to develop an early understanding of shale-gas wells performance where such detailed knowledge is vital to optimizing exploitation economics and estimation of reserves and resource potential.
Increasing CO2-Storage Efficiency through a CO2-Brine Displacement Approach
Authors: Akinnikawe Oyewande , Chaudhary Anish , Vasquez Oscar , Enih Chijioke , Ehlig-Economides Christine A.
Published: February 2011

Previous studies have shown that bulk CO2 injection in deep saline aquifers supplies insufficient aquifer storage efficiency and causes excessive risk due to aquifer pressurization. To avoid pressurization, we propose to produce the same volume of brine as is injected as CO2 in a CO2-brine displacement. Previous work showed that this increases the storage efficiency from 2% to 8%. However, this transforms the CO2 storage problem into a brine disposal problem. Therefore, we propose to desalinate the native brine and inject the saturated brine into the same aquifer while producing additional brine to maintain voidage balance.

A hypothetical case study using documented aquifer properties of the Woodbine aquifer in Texas indicates that the available volume is insufficient volume to store all of the CO2 being generated by power plants in the vicinity for more than 14 years. However, the CO2-brine displacement increases storage efficiency enough to store the CO2 produced for 84 years at the current rate of coal fired electric power generation. Using the reported brine salinity of the Woodbine aquifer, the energy requirements for CO2 transport and injection, brine production and transport, desalination, and saturated brine injection are estimated consistent with assumptions about the location of injection and production wells, the desalination unit or units, and whether desalinated water can be used by the power plant or for other uses.

While this approach may enable CO2 storage, the high energy cost ranging from 7.5% to 16% of the total power generation capacity is not insignificant, and comes with significant land use implications for injection and production wells, pipelines, etc. The importance of these results cannot be overstated.
Improved Stress-Anisotropy Characterization Through Casing in a 43-Year-Old Well Using Sonic and Cement/Borehole Imaging Data
Authors: Miersemann U.. , Marchina P.. , Prinet C.. , Loizzo M..
Published: February 2011

The RSE-1 well operated by Total is located within the Rousse field in the southwest of France. The 43 year old, depleted gas well has undergone extensive research in order to determine its suitability for CO2 storage. The main objective, in terms of containment, is to avoid the injected CO2 migrating back to the atmosphere or reaching potable aquifers, either through the well or the caprock itself. Openhole data from 43 years ago consisted only of 1-arm caliper and compressional sonic data. In order to predict geomechanical effects on the formation from production or CO2 injection, sonic shear data was acquired to compute elastic properties and the direction of maximum horizontal stresses in anisotropic zones. Breakout orientations from multi-arm/finger-calipers, corresponding to the minimum horizontal stress direction are used to improve the geomechanical analysis, especially in areas of strong stress anisotropy. This paper focuses on the acquisition of good quality stress data through casing essential for a geomechanical analysis of the caprock using sonic and cement/borehole imaging tools.

Since azimuthal sonic data is very sensitive to acoustic anisotropy, the available log was processed together with directional survey data to reveal a 75m-thick stress-induced anisotropic zone in the lower part of the caprock. The fast shear azimuth, which is associated with maximum horizontal stress direction as dispersion curves show the sonic anisotropy being the result of a horizontal stress imbalance, suggested a ENE-WSW compression. Evaluation of 3-D cement imaging data showed borehole breakouts along most of the annulus. The cement thickness map is equivalent to a 36-arm caliper through casing and the computed maximum hole diameter correlates well with the 1-arm openhole caliper data acquired 43 years ago. The associated breakout direction within the zone of anisotropy was determined to vary between NNW-SSE and NNE-SSW.

The fast shear azimuth computed during sonic processing is approximately perpendicular to the breakout direction acquired from the borehole images within the 75m-thick anisotropic zone. The overall NNE-SSW compression was confirmed by other well geometry data from the region. These results suggest that both measurements complement each other very well in a cased-hole environment and could be further used for geomechanical modeling.
The Effect of CO2-Saturated Brine on the Conductivity of Wellbore-Cement Fractures
Authors: Yalcinkaya Tevfik , Radonjic Mileva , Hughes Richard G. , Willson Clinton S. , Ham Kyungmin
Published: February 2011

The efficiency of Carbon Capture and Storage projects is directly related to the long term sealing ability of cemented sections in wellbores penetrating CO2 storage reservoirs. The microfractures inside the wellbore cement and/or microannulus are possible pathways for CO2 leakage to the surface and/or fresh water aquifers and jeopardize safe and long-term containment of CO2 in the subsurface.

This paper presents an experimental study which investigates the changes inside the cement internal structure when exposed to acidic brine through an artificial fracture. A 30-day long flow through experiment was conducted using a 1 in by 12 in. cement core and CO2 saturated brine, as a permeant, at a flow rate of 2 ml/min in a core flooding apparatus with10 psi and 600 psi of injection and net overburden pressures (Low Pressure-LP experiment). The same experiment was repeated with 1800 psi and 600 psi of injection and net overburden pressures for 10 days in order to account for the effects of pressure on the degradation process of cement (High Pressure-HP experiment). High-resolution X-ray computed tomography was used to image several subvolumes extracted from the flow-through cores. The images were processed and thresholded, followed by calculation of porosity. Total porosity was observed to decrease from 26% to 22% after 30 days of exposure of LP experiment. The HP experiment did not cause any significant change in total porosity possibly due to the short duration of the experiment.
Novel CO2 Capture Process Suitable for Near-Term CO2 EOR
Authors: Jain R..
Published: February 2011

Recent studies have indicted that more than 40 billion barrels of additional oil can be produced economically with CO2-EOR for a low CO2 capture cost and an oil price above $70/bbl. More than 10 billion tons of CO2, the equivalent of CO2 emissions from 50 1 GW power plants over a period of 30 years, can also be stored using CO2-EOR. Unfortunately, the cost of CO2 capture using current state-of-the-art absorption based post-combustion CO2 capture technologies is very high because of 25-30% reduction in the power plant output, and an 80-100% increase in the capital cost. These technologies are not viable in the near-term for CO2-EOR without a high market price for CO2. For this reason, most of the currently proposed CO2-EOR projects are based on IGCC plants that are yet to be built. This paper discusses a novel capture process based on physical sorption. Unlike the absorption based processes this process has a much lower CO2 capture cost, does not require the additional removal of NOX and SOX, and can be easily retrofitted to an existing power plant or refinery.

Based on extensive pilot testing over a period of over three years, detailed engineering designs, and detailed costing, the process can provide more than 99% CO2 purity and more than 90% CO2 recovery, and can produce pipeline quality CO2 with 60% lower capital cost and at least 40% lower energy penalty compared to the best current technology. The process will be tested with flue gas from a combustion source early next year and can become commercially available in 3-4 years. Lower capital requirements and <16% parasitic power can allow compressed CO2 production for less than $30/ton from existing power plants, refineries and chemical plants. This can allow many power plants and refineries near existing CO2 pipelines to become potential CO2 sources for near-term CO2-EOR in many locations in the United States.
Tengiz Sour Gas Injection Project
Authors: Darmentaev Sabyrzhan , Yessaliyeva Arailym , Azhigaliyeva Aizada , Belanger Dave , Sullivan Mike , King Greg , Feyijimi Tayo , Bateman Phil
Published: February 2011

Gas Injection into the Tengiz oilfield began in January 2007 with sweet gas injection as Phase 1 of the SGI pilot project. Phase 2 of the project, sour gas injection, began in October 2007, but was interrupted due to initial injection start up problems. Continuous sour gas injection began in January 2008. As part of the SGI Surveillance Plan, a variety of reservoir measurements are routinely acquired to monitor the progress of the flood.

The SGI project has four signposts for success: Compressor reliability, Injectivity, wellbore durability, and reservoir performance. The sour gas compressor at Tengiz was the first of its kind and has had greater than 90% availability when SGP has been operational. Injectivity has exceeded expectations and wellbore durability has also been excellent. The fourth area is reservoir performance and all indications are that the reservoir is performing as expected.

The SGI project consists of seven inverted five-spot patterns. To expedite data acquisition, the SGI well patterns were designed to include one "super-spot" pattern (twin injectors 100 m apart providing dedicated injection support to different geologic layers) and three short-spaced producers (producer-injector spacing approximately 1/3 of the standard spacing). Tracers, pulse tests, multiphase meters, gas saturation logging, and production and injection are used to monitor and understand reservoir performance. A specialized simulation model (Monitoring Model) was constructed which uses local grid refinement in the SGI pattern area.

On August 22, 2008, gas breakthrough occurred in Well T-318, the first of the short-spaced producers. This breakthrough was predicted with the Monitoring Model. Predictions from Monitoring Model suggest most likely breakthrough is near top of reservoir, and this was substantiated by logs. The gas injection project will continue to be closely monitored to improve our understanding and reservoir forecasts.
Using Electrical Borehole Image Log to Optimize Formation Pressure Sampling and Its Integration to Determine Structural/Stratigraphic Break in a Tight Carbonate Reservoir at Karachaganak Field
Authors: Juandi D.. , El-Battawy A.. , Russo J.. , Chittick S..
Published: February 2011

Karachaganak field hosts world-class gas and liquid reserves in an Upper Devonian to Lower Permian isolated carbonate platform. A complex diagenesis over carbonate rocks extends from syndepositional to deep burial settings. Effective porosity in most parts of the reservoir is secondary in nature, such as vugs and fractures, with average porosity considered as low. The complexity of carbonate reservoirs is well known owing to the nature of their heterogeneity and cannot be resolved by conventional openhole logs because of limited vertical resolution and large azimuthal dependency.

Electrical borehole image logs provide both the small-scale resolution and azimuthal coverage to quantitatively resolve the heterogeneous nature and are used routinely to determine subseismic structural or stratigraphic events, as well as to optimize the selection of formation pressure and sampling points. The use of a high-resolution electrical borehole image log helps place the tool probes at optimum formation and depth locations, thereby reducing risk and operating time. Analysis of pressure gradients can confirm subseismic reservoir barriers that had been earlier interpreted as structural or stratigraphic breaks.

Two case studies from nearby vertical Wells A and B are described. Well A has a fieldwide unconformity surface picked at a depth of X610 m MD, indicated by a drag pattern in the overlying zone. The carboniferous section in that well is composed of numerous shoaling upward cycles. Any of these cycle tops can act as a vertical permeability barrier and result in a step in the pressure profile. Meanwhile, Well B has an unconformity within the internal Permian at a depth of X142.5 m MD, indicated by the drag pattern. The fieldwide unconformity and a stratigraphic barrier can be proved by a shift of pressure gradient at a depth of X608 m MD, indicated by a change of dip attitude.
Slope Heterogeneity and Production Results in a Steep-sided Upper Paleozoic Isolated Carbonate Platform Reservoir, Karachaganak Field, Kazakhstan
Authors: Katz David A. , Playton Ted , Bellian Jerome , Harris Paul, (Mitch) , Harrison Christopher , Maharaja Amisha
Published: February 2011

Slopes that flank steep, reef-rimmed carbonate platforms are depositionally complex due to a variety of autochthonous and allochthonous deposit types that exhibit vertical and lateral variability. Karachaganak Field, northern Pricaspian Basin, Kazakhstan, is a Permo-Carboniferous isolated carbonate platform with a hydrocarbon column that resides primarily within steep foreslope strata. Historically, the distribution of reservoir properties at Karachaganak has been poorly understood owing to the depositional heterogeneity common in slope environments. These uncertainties were assessed by integrating seismic facies analysis, relevant high-quality outcrop analogues, cores, and log data to produce a detailed depositional model of Karachaganak slopes that predicts compositional and architectural variability. Recent well lookbacks were also performed to assess the impact of carbonate foreslope characterization on well location and design in the current drilling program.

Seismic facies analysis with support from outcrop analogues and forward models reveals depositional regions within stratigraphic intervals that can be further divided into multiple styles of clinoforms, slope and basin sediment wedges, margin configurations, and secondary features (i.e. reentrants). Each of the seismic facies is in turn defined by reflector characteristics, such as continuity, intensity, and geometry. Seismic mapping of the abovementioned elements with corroboration from other subsurface data identifies heterogeneity at well, flow unit, and field scales, including 1) bedset-scale variations internal to clinoforms and wedges, 2) along strike and temporal variations in clinoform or wedge style, and 3) platform-scale asymmetry.

Integration of core and log data, combined with insights from outcrop analogues, allows for prediction of the depositional rock types and depositional regions within the stratigraphy mapped at Karachaganak. Spatial and stratigraphic trends regarding reservoir properties and connectivity are extractable based on the mapped geographic distribution of different clinoform styles, wedge types, and secondary features. Overall, this approach links seismic-scale architecture, petrophysical behavior, and geographic distribution, thereby providing insights for future reservoir development and modeling at Karachaganak. For example, recent production data from the current drilling program shows that wells in the youngest Carboniferous distal slope settings are among the poorest producers due to depositional heterogeneity and disconnected compartments - characteristics that the conceptual model and base case reservoir model predicts. Recent results from wells with trajectories that tatget older slopes are a success and validate both the conceptual geological and reservoir models.