bluuebunny/crossref_metadata_2025 huggingface dataset:
Deviation From Standard Sandstone Acidizing Practices: Chronicle of a Forgiving Acid System
Authors: Obadare A. , Ighodaro O. , Nwoke L. , Onwusika K. , Osadjere P.
Published: December 2007

The process of sandstone acidizing is fraught with the danger of further damaging the reservoir. The odds of increasing formation damage is raised if standard acidizing practices are not followed primarily due to non-technically related issues like logistics.

This paper reviews the stimulation of two low-pressure oil producers and another oil producer, which was previously producing below potential. Standard practice indicates that a HF based system be flowed back or lifted with nitrogen to reduce the risk of additional formation damage due to factors including emulsion / sludge / secondary precipitate formation.

For these case histories, the residence time of the acid in the reservoir was between 18 hrs to 96 hrs due to the non-availability of nitrogen and poor well inflow. The remarkable aspect of these operations was that there was no evidence of further impairment in all the wells. In fact, two of the wells demonstrated superior performance after production rate stabilized. These successes are partially attributed to the unique chemistry of the retarded acid system, favorable rock mineralogy, exhaustive lab testing / field QC, the presence of an acidic over flush and the use of additives that prevented formation of emulsion and sludge.

This acid system can be used in depleted / low GOR reservoirs where over-displacing is a poor option in the absence of flow-back aid and also for single stage acidizing in low carbonate sandstone reservoirs.

This paper attempts to follow through the process of candidate selection with a focus on nodal analysis. It also defines the factors affecting success rates in the stimulation of depleted reservoirs, offers a superior acidizing system for mitigating the effect of deviations from standard acidizing practices and reinforces the possibility of single step sandstone acidizing (with a brine cushion ahead) especially in low carbonate content sandstone.
Aqueous Discharges From E&P Installations: Current Technical and Regulatory Challenges From an Operator's Point of View
Authors: Garland E. , Prunier A.
Published: December 2007

The regulatory regime applicable to the onshore discharge of aqueous waste streams generated by Exploration and Production (E&P) facilities differs from the one(s) applicable to offshore discharges.

The example of the European Union framework Directives shows the importance given to the characteristics of the receiving environment when regulating onshore discharges, while offshore, the regulatory regime, led by international (MARPOL) or regional conventions (such as OSPAR or the Kuwait Convention), primarily focuses on the source of the aqueous discharges. Today, offshore regulations are a compromise between aspirational goals and practicalities, as the recent development of interpretation of MARPOL rules regarding FPSOs and FSUs shows.

The second part of the paper describes the basic principles developed by TOTAL to elaborate a realistic and sustainable position when regulations fail to provide sufficient guidance. Key widely accepted international conventions serve as a basis for internal standards while provisions of the regional conventions guide us when elaborating local standards for a specific installation, together with due consideration to the actual or forecast impact of aqueous discharges to the environment.
Results of a Laboratory Propellant Fracturing Test in a Colton Sandstone Block
Authors: Wieland C. W. , Miskimins J. L. , Black A. D. , Green S. J.
Published: December 2007

The use of high energy material to stimulate production has been practiced in the oilfield since early in the industry's history. While the materials used for stimulation have progressed from explosive materials to propellants, the basic concept remains the same. A highly energetic material is burned in the wellbore and the gasses and energy released cause the rapid pressurization and breakdown of the formation. This breakdown is capable of generating multiple fractures with certain geometric properties.

To investigate and confirm the generation of propellant induced fractures in low permeabililty formations, a large scale laboratory test was designed and conducted at the TerraTek, Inc. laboratories in Salt Lake City, Utah. The test was conducted on a 30"x30"x36" Colton Sandstone block that was loaded in a poly-axial stress frame to predetermined reservoir conditions. A scaled wellbore, drilled in the center of the block, contained the propellant charge. After the block was properly stressed, the propellant charge was deflagrated. The block contained several pressure probes imbedded in the block and located in the wellbore that were capable of sampling at extremely high rates (milliseconds) to capture the full response of the propellant burn.

Upon completion of the deflagration, the block was removed from the test frame and cut horizontally to examine the fracture pattern generated by the propellant burn. Each half was later split along the primary fracture to examine the height growth and fracture lengths generated by the propellant stimulation.

This paper discusses the test design and execution, the resulting fracture geometries and analyzes the pressure responses witnessed during the propellant deflagration. The results show laboratory verification of some propellant fracture theories and provide insight to the effects of propellant deflagration in field applications.
Development of a Generic Life-Cycle Modeling Tool
Authors: Woodhead T.
Published: December 2007

The Shell integrated modelling tool ‘HFPT’ (Hydrocarbon Field Planning Tool) has been used to generate a generic single life cycle model in which the appropriate business focus at each stage of the business cycle is maintained.

This model has been applied to two very different development projects, the first being a single oil field multiple reservoir development and the second a large integrated multi-field gas node, both in the Niger Delta. In each case, the tool was successfully used to evaluate alternative business developments using multiple scenario modelling techniques.

The model results show the capabilities of the tool in providing a focus on the business decisions required at key stages of the development life cycle and the ability of the tool to provide the appropriate amount of surface and sub-surface detail for addressing the development decisions to be made at each stage

The Shell integrated modelling methodology places a strong emphasis on achieving the appropriate focus at each step in the business cycle. In particular, the net is cast wide at the ‘feasibility’ stage requiring large numbers of development opportunities to be evaluated using simple or coarse modelling. As the project progresses, there is a requirement to add detail and to develop more complex models as the project moves towards concept selection. The smooth and seamless transition between these stages has always been an issue and has typically lead to the use of ad-hoc tools at the feasibility stage with the requirement to later re-derive and confirm these results from scratch using detailed models. The new tool promotes a true ‘life cycle’ modelling approach to asset development and a robust audit trail between each of the different levels of modelling
Achieving Zero Accidents in Marine Stimulation Vessels
Authors: Mayor L. , Boing O. , Santos A.
Published: December 2007

Operations of marine stimulation vessels are considered a highly risky activity, by the standards of oil and gas industry. Activity performed by these vessels include acidizing, hydraulic fracturing, scale, asphaltene, hydrate, water, and sand control. The inherent hazards related to the nature of manipulated fluids involved on these different scenarios, comprised by acids in different strengths, non aromatic solvents, chemical inhibitors, and the pressure under which they are usually pumped into an oil or gas well, added to vessels navigation hazards such as potential leaks, sea and weather conditions, contribute to the risk involved.

In addition, confinement created by lack of space, and the need to run simultaneous work, such as pumping and maintenance on the stimulation plant, add to the overall risk, involving health, safety and environmental components. It is like having in the same site the Base Plant and the Well.

Exposure to chemicals, relatively high noise levels, weather conditions and stress due to marine confinement is a daily reality to the workforce. Simply there is no room for mistakes.

To control and minimize these risks, oil industry has applied intense efforts. Incorporation of new technologies, development of better personnel protective equipment, improvement of procedures and workforce training/qualification are concrete examples of these efforts.

Specific management tools have also been applied in the search of an accident free environment, and are mentioned on this paper. Additional efforts will be required to continue running a zero accident environment. These efforts include the development and maintenance of a high level culture with focus on human behavior.

This paper describes how the application of a safety culture, together with traditional safety management tools ended accidents and allowed achieving two consecutive years without accidents by two marine stimulation vessels operating in Brazilian coast, Macae Basin.
Critical Issues in CO2 Capture and Storage: Findings of the SPE Advanced Technology Workshop (ATW) on Carbon Sequestration
Authors: Imbus S. , Orr F. M. , Kuuskraa V. A. , Kheshgi H. , Bennaceur K. , Gupta N. , Rigg A. , Hovorka S. , Myer L. , Benson S.
Published: December 2007

Carbon dioxide capture and storage (CCS) is emerging as a key technology for greenhouse gas (GHG) mitigation. The Society of Petroleum Engineers (SPE) Applied Technology Workshop (ATW) on CO2 Sequestration (Galveston Island, Texas, Nov. 15-17, 2005) convened a diverse group of geoscience, engineering, economics and stakeholder experts to review the status of CCS and to identify the remaining critical issues that still serve as barriers to its acceptance and widespread deployment.

Site assessment can be improved with systematic, generally accepted approaches that identify and focus on injection, capacity and containment risks. Reservoir simulation models can be adapted from oil and gas applications but further experimental work and code development are needed to quantify the role of major CO2 trapping mechanisms. Enhanced hydrocarbon recovery accompanying injection of CO2 is well established for CO2 EOR but its efficacy in EGR and ECBM is unclear. Well integrity, a key vulnerability in CO2 storage, should be addressed through modified well materials and construction approaches and cost effective remediation and intervention techniques. Field management issues, including risk assessment and monitoring, would benefit from development of accepted practices to apply through project lifecycle.

Overall, the Workshop participants concluded that implementation of CCS, in a timely manner, represents a complex challenge that requires coordination of technical expertise, economic incentives, appropriate regulations and public acceptance. Storage assessment tools are available and adequate, although in need of refinement and standardization. Capture technology, however, requires more intense research aimed at new technologies and deep cost reduction. Infrastructure and regulatory development needs to reflect expectations and incentives from government bodies. Early implementation of CCS is expected to focus on the gas processing and other industries that produce high purity CO2 with storage in local hydrocarbon reservoirs or saline aquifers. Deployment at a scale required to substantially reduce CO2 atmospheric concentrations, however, would rely heavily on injection into saline formations and take decades of investment to build the extensive infrastructure required to capture and transport CO2 to injection sites.

The ATW gathering was a unique, timely opportunity to engage experts in an assessment of the status and best path forward for CCS.
Recovery of Oil Resources from the Residual and Transitional Oil Zones of the Permian Basin
Authors: Koperna G. J. , Melzer L. S. , Kuuskraa V. A.
Published: December 2007

Because of their low to moderate oil saturations, the immobile (but significant) oil resources in the transition and residual oil zones (TZ/ROZ) are not economic to produce using primary/secondary oil recovery techniques. As such, the great majority of domestic oil wells are completed at the first evidence of mobile water (oil-water contact) above the TZ/ROZ. Outside of a small group of forward-looking operators, little is known about the ability to target and produce this large TZ/ROZ resource. However, in the current economic climate and with technology advances, the TZ/ROZ resource offers a new source of domestic oil production. The relatively thick (100s of feet) TZ/ROZ located beneath the traditional main pay zones of Permian Basin oil reservoirs provides an attractive domestic development resource.

Carbon dioxide (CO2) enhanced oil recovery (EOR) is a viable technique for recovering immobile residual oil left behind ("stranded") after waterflooding. Further, the oil saturation in the TZ/ROZ portion of a reservoir is often similar to the oil saturation left after waterflooding. As such, with progress in CO2 flooding technology and availability of affordable supplies of CO2, the oil in the TZ/ROZ could become an economically viable target.

This paper will provide updates for four key TZ/ROZ projects (two in the Wasson oil field, one in the Seminole San Andres Unit and a fourth at Salt Creek). These pilot projects plus reservoir simulation work by the authors show that this residual oil can be efficiently recovered using CO2-EOR. The paper discusses how two CO2-EOR practices, selective completions and joint development with the main pay zone, would enable the recovery of the TZ/ROZ resource to be optimized. The paper concludes with an assessment of how much resource potential in the TZ/ROZ may hold for future oil development with the Permian Basin.
Scatter Search Metaheuristic Applied to the History-Matching Problem
Authors: Sousa S. H. G. , Maschio C. , Schiozer D. J.
Published: December 2007

Reservoir simulation plays an important role in managerial decisions during the life of a reservoir, so it is vital that they present an accurate prospect of real reservoir performance. The main goal of the History Matching (HM) process is to improve the quality of numerical models by constraining simulated to observed data. A typical HM process evaluates a chosen objective function (OF) comprised by linear functions on the uncertain reservoir properties. The OF can be modeled in such a way that the HM process can be solved as an optimization problem. This paper discusses how the Scatter Search (SS) technique can solve the HM problem. The main feature of SS is that it works on a set of solutions called the reference set (RefSet). The idea is to improve the overall quality of the RefSet. New solutions are generated by a non-convex combination of explored solutions. The goal of this paper is solve the HM with SS and to evaluate its performance.

The proposed methodology was tested with two base synthetic reservoir models. The first is a homogenous reservoir with 8 different horizontal permeability regions, while the second is a highly heterogeneous reservoir model where low quality background sand is crossed by high permeability canals. The results show that SS was quite efficient, considering the quality of the generated solutions and the number of required numerical simulations.

Most of the current HM methodologies do not perform well when the solution space is large and complex. The application of the SS methodology to the HM problem is a novel approach. Unlike most metaheuristics, SS can be effective even when the simulation time of each tentative solution to the problem is long.
Mechanical Automation in the Oilfield To Help HSE Programs
Authors: Ross S. E. , Havalda R. A. , Havalda P. A.
Published: December 2007

This paper attempts to address the continuing occurrence of major HSE incidents in the Oil Industry with emphasis on the trend of automation to help reduce these expensive and lethal incidents.

Today we cannot imagine a machine shop or the automobile industry operating without computerized or robotic controlled machinery (such as the common CNC system) to turn out high precision mechanical parts and our fancy cars that we drive everywhere any day of the week.

It took awhile but the task of automation has started to make its way below the rotary table on the drilling rig. The computer is now handling functions handled traditionally by the Directional Driller.

Rotary steerable tools that are comprised of articulated connections and adjustable angle stabilizers run behind the bit now routinely allow the Oil Industry to weave a directional well from vertical to horizontal to even more severe angles while operating tens of thousands of feet from the drilling rig and tens of thousands of feet below the earth's surface.

With the continuing increase in marginal field developments particularly in the North Sea, there has been a continuous trend towards unmanned facilities to reduce operating cost and reduce safety related incidents.

The recent refinery incident in Texas for BP and the loss of the entire Piper Alpha and Bombay High platforms in the North Sea and the Indian Ocean are major capital losses coupled with injuries and loss of life.

Most everything in life has risks attached and our operations in the Oil Industry have especially higher risk due to the precious but highly flammable hydrocarbons that we find, produce, refine, and market for world consumption.

Thanks to higher prices for oil and gas, producing the higher risk oil and gas fields which were once before deemed uneconomic will now find their way to market. Without comprehensive HSE programs that include automation, history's major incidents will continue to shock our industry and many families alike.
Effect of Non-Darcy Flow on Well Productivity of a Hydraulically Fractured Gas/Condensate Well
Authors: Mohan J. , Pope G. A. , Sharma M. M.
Published: December 2007

Hydraulic fracturing is a common way to improve productivity of gas-condensate wells. Previous simulation studies have predicted much larger increases in well productivity than actually observed in the field. This paper shows the large impact of non-Darcy flow and condensate accumulation on the productivity of a hydraulically fractured gas-condensate well. Two-level local grid refinement was used to so that very small gridblocks corresponding to actual fracture width could be simulated. The actual fracture width must be used accurately model non-Darcy flow. An unrealistically large fracture width in the simulations underestimates the effect of non-Darcy flow in hydraulic fractures. Various other factors governing the productivity improvement such as fracture length, fracture conductivity, well flow rates and reservoir parameters have been analyzed. Productivity improvements were found to be overestimated by a factor as high as 3 if non-Darcy flow was neglected. Results are presented that show the impact of condensate buildup on long-term productivity of wells in both rich and lean gas condensate reservoirs.
A Digital Pressure Derivative Technique for Pressure Transient Well Testing and Reservoir Characterization
Authors: Veneruso A. F. , Spath J.
Published: December 2007

The pressure derivative has become the primary interpretation tool for diagnosing well and reservoir behavior. In many situations however, the derivative of the measured pressure data is uninterpretable or, worse, mis interpreted because of various artifacts collectively termed noise. While various noise-smoothing techniques have been used, there are valid concerns that smoothing procedures may adversely affect the well-test interpretation. In contrast, measurements from new pressure gauge systems can now provide the stability and resolution required to characterize/quantify complexities of the well/reservoir system, which may otherwise have gone unnoticed.

In this paper we endeavor to reconcile the advances in well-test interpretation and in measurement technology. Specifically, we describe a new technique for differentiating well-test-pressure data, the digital pressure derivative technique. This approach produces the most accurate and representative dp/dt curve by incorporating knowledge of both reservoir and pressure-gauge physics. This technique is efficient and straightforward to imp lement and may be used on both real-time and recorded data. No modifications to gauges or other hardware are necessary. The technique enables analysts to customize the differentiation based on the measured-data quality without a need for subjective smoothing algorithms. Examples are presented using field measurements to illustrate the technique.
Understanding the Effects of Cesium/Potassium Formate Fluid on Well Log Response—A Case Study of the Kristin and Kvitebjorn Fields, Offshore Norway
Authors: Pedersen B. K. , Pedersen E. S. , Morriss S. , Constable M. V. , Vissapragada B. , Sibbit A. , Stoller C. , Almaguer J. , Evans M. , Shray F. , Grau J. , Fordham E. , Minh C. C. , Scott H. , McKeon D.
Published: December 2007

Kristin is a high-pressure, (90 MPa), high-temperature (exceeding 160°C) gas condensate field operated by Statoil ASA. Kvitebjorn is another gas condensate field with slightly lower pressure and temperature around 78MPa and 150°C respectively. In some of the production wells in these fields, a blend of cesium and potassium (CsK) formate was selected as the drilling fluid, to ensure a stable mud density for well control and in order to reduce formation damage.

Formate muds present a serious challenge to well-log interpretation because both the mud and the filtrate have properties significantly different from conventional oil-and water-based muds. The nuclear log properties of CsK formate that are particularly challenging include high density, high photo electric factor (Pe), low hydrogen index (HI), and high thermal neutron capture cross-section (Sigma). To quantify the borehole and invasion effects on logs acquired in this environment, extensive laboratory experiments and mathematical modeling were carried out for relevant wireline (WL) and logging -while- drilling (LWD) tools.

The laboratory measurements confirmed dramatic effects on nuclear tools. These effects increase with increasing formate fluid density and depth of invasion of the formate fluid. The effects of fluid invasion were so severe that porosity estimation from nuclear logs appeared to be unattainable, unless invasion is shallow and precisely known. LWD data acquired in the first well confirmed these large effects and showed significant changes with time. It was observed that the effect of CsK formate is relatively less on wireline density logs when compared to that of LWD density logs. The proposed explanation is that a significant quantity of gas was present in the invaded zone at the time of WL logging. Nuclear modeling demonstrated that such an explanation is plausible. The basic design differences between WL and LWD tools may also be contributing to the effect.

This case study demonstrates that a reasonable log interpretation is possible in wells drilled with heavy formate muds, albeit with reduced accuracy and precision.
Prediction of Injection-Fluid Distributions for Multiple Zones—Intelligent Injection System
Authors: Sun K. , Konopczynski M. R.
Published: December 2007

Injection fluid distributions present a challenge for the applications of multi-zones intelligent well injection systems. This paper presents two approaches to fulfill this need. The first approach is to apply the available downhole real-time data to calculate fluid distribution based on the existing single phase flow modeling and flow coefficient (Cv) test data of down-hole Interval Control Valve (ICV). For this method, a fluid distribution model for a multi-zone intelligent injection system is derived, and an example of the application of the first method is presented. For the second approach method, zonal reservoir pressure/temperature and injectivity data are considered in the fluid distribution calculation. This method is based on a balanced pressure-system approach. In this paper, each of these fluid distribution prediction methods considers the choke setting of the multi-position ICV, the completion string's geometric sizes, injection fluid characteristics, available wellhead pressure/temperature data, and the reservoir pressure/injectivity data (or measured down-hole real-time data) to do the fluid distribution prediction.

To demonstrate these methods, a hypothetical example of a two-zone intelligent water injection case is illustrated in this paper. The example shows how to use the wellhead pressure/temperature data, zonal reservoir pressure/injectivity data (or measured down-hole real-time pressure/temperature data), with completion string's geometry sizes and ICV positions to predict injection fluid distributions through each zonal ICV. An intelligent injection system operation analysis has been presented based the theoretical models and illustrated example.

The technical contributions of this paper include: Present mathematical models which apply the available downhole real-time data to calculate fluid distribution.Propose a balanced pressure-system search method which applies the zonal reservoir pressure and injectivity to calculate fluid distribution.Present an intelligent injection system operation analysis, which reveals the key roles of changing ICV position and wellhead pressure in the controlling of injection fluid distributions.Present an effective way to handle down-hole realtime data for intelligent injection system.
Rehabilitation of Complex, Massive, and Aged Pipeline Infrastructure in the Gulf of Suez
Authors: Zekry M. M. , Abd El Latif Waleed , Emam A.
Published: December 2007

The paper describes the Rehabilitation program developed by GUPCO to ensure that its offshore production facilities retain in safe operating condition through a monitoring and preventive approach. During last five years significant increase in the amounts of acid gases (H2S & CO2) was noticed as some reservoirs have soured under the action of substantial water flood operations and the new high H2S wells.

Moreover water cut in produced fluids has steadily increased over the years andnow averages about 60 %, with some fields as high as 90 %. These problems are further aggravated by activity of Sulphate Reducing Bacteria (SRB) in some producing reservoirs. The aging of oil production reservoirs and associated facilities has resulted in significant corrosion problems and repeated failures throughout offshore facilities.

An extensive range of corrosion mechanisms have been observed, various equipment failures described, including those from offshore, pipeline and onshore process equipment. However, some have been particularly troublesome either in terms of their economic loss potential, their tenacity or the threats posed to personnel safety and the environment. These are briefly surveyed in the paper. Also we discuss the re-qualification programs of the existing offshore platforms and define our criteria to evaluate the adequacy and acceptability of the rehabilitation programs including design, construction, operation, inspection and maintenance of pipelines operations.

Furthermore, we describes a successful case history for early detection and evolution of reservoir souring due to microbial activity at one of the highest producing reservoirs at GOS fields (Badri field) based on our experience and a set of improved laboratory evaluation tests.

Moreover, paper shows in a systematic way the latest research results for Corrosion inhibition of carbon steel in acidic medium using some natural products and heterocyclic compounds containing nitrogen or sulphur.
Portable Multiphase Production Tester for High-Water-Cut Wells
Authors: Oglesby K. D. , Mehdizadeh P. , Rodger G. J.
Published: December 2007

Accurate well testing is required for making intelligent decisions on oil and gas production wells. This paper reports on an effort to assess the application of multiphase metering technology to high water-cut (75+% water) and high volume production wells, as found in many North American Mid-Continent brown fields. A portable multiphase oil, water and gas production well tester was designed and field tested for these wells. Key components of the trailer mounted and battery operated tester are: a compact gas-liquid cylindrical cyclonic (GLCC) separator with control valves, GLCC bypass valving, coriolis liquid meter, infrared water-cut meter, vortex shedding gas meter and a data acquisition unit. One key finding is that separation is not needed in many such applications, thereby significantly reducing the size, weight and cost of future testers. This is due to the inherent downhole well separation and annulus venting used in most such well configurations along with specific coriolis/water-cut meter combinations allowing accurate measurements with gas content up to 10 to 20% GVF.
Efficient Parallel Computing Using Multiscale Multimesh Reservoir Simulation
Authors: Atan S. , Kazemi H. , Caldwell D. H.
Published: December 2007

The multiscale, multimesh flow simulators have been designed for the sole purpose of running very large, heterogeneous reservoir, flow problems on massively parallel computers. This paper shows the flow simulation results and the corresponding CPU times. The multiscale flow simulator is written in Fortran 90/95 with OpenMP directives and compiled on high-performance SMP computers. The simulations were performed for several highly heterogeneous, channelized, reservoir cases with realistic rock-fluid interaction (viscous, capillarity, gravity, and compressibility) to evaluate the efficacy of the multiscale, multimesh simulation in parallel computing. It is shown that the aforementioned multiscale technique reduces computing time by several orders of magnitude, while maintaining the same accuracy as the conventional fine scale simulation.
Determining Anisotropic Formation Resistivity at Any Relative Dip Using a Multiarray Triaxial Induction Tool
Authors: Wang H. , Barber T. , Morriss C. , Rosthal R. , Hayden R. , Markley M.
Published: December 2007

Thin-bedded sand-shale sequences frequently exhibit resistivity anisotropy. That is, resistivity measured perpendicular to the bedding (Rv) is significantly higher than the resistivity measured parallel to the bedding (Rh). It is difficult to determine water saturation in these sequences using standard induction logs that respond primarily to Rh, regardless of relative dip angle. If conductive shale laminations are present, the water saturation is over estimated; equivalently, hydrocarbon in place is underestimated.

A recently introduced triaxial induction tool provides several 3×3 tensor measurements that are sensitive to Rh, Rv and formation dip. A fast and rigorous inversion of triaxial induction data provides logs of Rh, and Rv without shoulder bed effect, and also provides logs of formation dip. The robustness of the inversion algorithm has been validated with synthetic log data.

A petrophysical model has been developed that computes both sand resistivity (Rsand) and shale resistivity (Rshale) from Rh and Rv logs. Fraction of shale, determined using established log interpretation techniques, is an input to the model. Since the induction measurement is relatively deep, the uncertainty in water saturation using the model is greatly reduced compared to interpretation models that use microresistivity logs.

Case studies from oilfields around the world demonstrate the utility of triaxial induction measurements for formation evaluation. Data were acquired in a wide variety of borehole and formation environments. These include oil-based mud, waterbase mud, dipping formations, vertical wells, deviated wells, and a wide-range of borehole sizes. Low resistivity pay zones were identified that might otherwise be missed with standard induction logs. Microresistivity images confirmed the presence of thin laminations and confirmed the dip measurements from the triaxial induction.
Experimental Development of Adsorption and Desorption Kinetics of a CO2-Foaming Surfactant Onto Berea Sandstone
Authors: Zeng Z. , Grigg R. B. , Bai B.
Published: December 2007

Results of eight series of adsorption and seven series of desorption experiments of CO2 foaming surfactant CD1045 onto and from Berea sandstone, each with a different initial concentration, are presented in this paper. Non-linear pseudo first and second order kinetic models for adsorption and desorption processes were derived. A simplex optimization method was adapted for the calculation of kinetic parameters of these models. This method can be used for calculating not only the kinetic model parameters, but also the absolute errors between the model and the measurements, and thus the fitness of the model. Using this simplex method and the experimental results, the adsorption and desorption processes of CD1045 onto and from Berea sandstone were found to follow pseudo second order adsorption model and pseudo first order desorption model, respectively.
Electrical Impedance Tomography (EIT) Technique for Real-Time Saturation Monitoring
Authors: Stacey R. W. , Li K. , Horne R. N.
Published: December 2007

Three-dimensional Electrical Impedance Tomography (EIT) is a technique that has the potential to provide estimates of reservoir saturation at multiple scales by determining the resistivity distribution within the subsurface. In theory EIT is well suited for researching oil and brine systems due to the large contrast in resistivity between the two phases. Here in our initial laboratory investigation we have applied the EIT technique to measure the saturation distribution of water within a core.

The initial EIT experiment presented here used a Berea sandstone core with 48 electrodes attached in three rings of 16. The core was open to the atmosphere with saturation occurring by natural imbibition and desaturation by evaporation. The voltage potential field was measured by applying a direct current pulse across the core and measuring the voltage potential at all electrodes, essentially applying the 4-wire resistance technique over all electrodes in turn. The result was a data set that embodies the resistivity distribution within the core, and by inversion the resistivity distribution was reconstructed, which allowed for the inference of the saturation.

The data processing was accomplished by utilizing the EIDORS toolkit which was developed for application to this nonlinear and ill-posed inverse problem. The procedure utilizes a finite-element model for forward calculation and a regularized nonlinear inverse solver to obtain a unique and stable inverse solution1.

Experiments have indicated EIT is a viable technique for studying the displacement characteristics of fluids with contrasting resistivity, and is capable of detecting displacement fronts in near real-time. The current system is also a quantitative technique able to measure saturation distributions accurately between 20% < Sw < 65%. These limitations were imposed due to connate water connections to the electrodes and ion mobility effects caused by the DC voltage source. It is anticipated that the applicability of EIT will increase with the implementation of an AC voltage source.
Factors Controlling the Proper Design of Effective Insulation Fluids for Oilfield Applications
Authors: Wang X. , Qu Q. , Stevens R. , Javora P.
Published: December 2007

Flow assurance has been a major consideration in deep water completions where undesired heat loss from production tubing to outer annuli can lead to the deposition of sludge, paraffin and asphaltene materials, the formation of gas hydrates, and cause severe flow assurance problems and loss of productivity. In recent years, thermal insulation fluids have been successfully applied in wellbore and deepwater risers to prevent undesired heat loss. Case histories have demonstrated that installation of insulation fluids is an effective alternative to conventional insulation options such as an external insulation or nitrogen gas for deepwater risers. These successes have made this insulation technology the preferred method in many GOM Deepwater projects.

Field practices and flow assurance simulations have shown that the ideal thermal insulation fluid design relies on effectively confining thermal convection and minimizing effective thermal conductivity of the fluid. How do fluid compositions affect these factors? What is required for an insulation fluid to be effective in an oilfield installation? These questions will be addressed.

This paper will discuss the proper testing methods that are relevant to oilfield flow assurance reality and are required to qualify thermal insulation fluids fit-for-use. Fluid rheology and intrinsic thermal conductivity have been assumed by some as two controlling factors for an effective thermal insulation fluid, especially in typical flow assurance simulations. Utilizing proven testing methods, these assumptions will be re-examined and discussed in terms of oilfield thermal insulation reality. Relationship between fluid chemical composition, fluid rheology and effective thermal insulation will be explored. Findings on how to optimize the fluid compositions to achieve the desired insulating potential and make the application of such fluid economical and practical in the field will be presented. Selected field cases will be discussed in reference to these recent findings.
Screening for Potential Asphaltene Problems
Authors: Wang J. X. , Creek J. L. , Buckley J. S.
Published: December 2007

We present a rapid screening technique that uses a minimal amount of measured data. Only in cases where asphaltene precipitation is predicted by the screening test would further experimental evidence, such as the measurement of onset pressure, be required. Currently the criteria introduced by de Boer et al.1 are widely used for screening purposes. In general, these criteria yield predictions that are somewhat pessimistic, in part because they fail to account for differences in stability between specific oils and their asphaltenes.

In this paper we propose a practical screening method that is easily applied, yet can dramatically improve the accuracy of stability predictions. The method is a modification of the ASphaltene InStability Trend (ASIST) technique2 for predicting the onset pressure during depressurization. The information required in the simplified screening method includes routine PVT data, compositional analyses, and a single onset titration using stock-tank oil and a light n-alkane precipitant such as n-heptane. The predicted onset solubility parameter at the bubble point is compared with the calculated solubility parameter of crude oil at that pressure to determine whether asphaltene would become unstable and precipitate. Twenty-seven crude oil samples from many different locations have been used to develop and test this method. Results are in agreement with the more detailed ASIST predictions and clearly identify specific cases where de Boer predictions are overly pessimistic.
Effect of Water Depth on Bridging Tendencies in Ultradeepwater Blowouts in Gulf of Mexico
Authors: Nesheli B. A. , Schubert J. J.
Published: December 2007

A blowout is an uncontrolled flow of reservoir fluids into the wellbore to the surface, causing serious, sometimes catastrophic, problems in different types of petroleum engineering operations. If the formation's strength is low and the pore pressure is high, bridging can be a very effective method for blowout containment. In this method, the formation caves into the open hole or onto the casing and stops the flow of the formation's fluid, either naturally or intentionally. This method can be effective in deepwater blowouts where the formation has high pore pressure and considerable shale intervals with low strength.

In this paper, wellbore stability and fluid flow performance subroutines have been developed with Visual Basic for Applications (VBA) programming. By integrating the subroutines together, we made a simulation tool to predict wellbore stability during blowouts and, consequently, predict wellbore bridging during normal and blowout situations. Then we used a real case in the country of Brunei to investigate a field case of a bridged wellbore to validate the simulator.

Based on this simulation tool we are able to determine the potential location of bridging during the blowout situation and compared the model with real data and field observations during normal and blowout situations. The difference between our simulator and existing models is that existing simulators only determine breakouts in static situations not during the blowout.

In the final part of this paper we studied the effect of water depth on bridging tendency during a blowout for the deepwater Gulf of Mexico (GOM). Since we could not find much real data in this area, we used general trends and correlations related to the GOM for parts of our study. The results of our study showed that water depth delays the occurrences of breakout in the wellbore during blowouts (i.e. for greater depth of water, wellbore collapse occurs farther below the mudline). However, the depth in which collapse occurs is different for different maximum horizontal stress amounts.
Exact Solutions in a Model of Vertical Gas Migration
Authors: Silin Dmitriy B. , Patzek Tad W. , Benson Sally M.
Published: December 2007

This work is motivated by the growing interest in injecting carbon dioxide into deep geological formations as a means of avoiding atmospheric emissions of carbon dioxide and consequent global warming. One of the key questions regarding the feasibility of this technology is the potential rate of leakage out of the primary storage formation.

We seek exact solutions in a model of gas flow driven by a combination of buoyancy, viscous and capillary forces. Different combinations of these forces and characteristic length scales of the processes lead to different time scaling and different types of solutions. In the case of a thin tight seal, where the impact of gravity is negligible relative to capillary and viscous forces, a Ryzhik-type solution implies square-root of time scaling of plume propagation velocity. In the general case, a gas plume has two stable zones, which can be described by travelling-wave solutions. The theoretical maximum of the velocity of plume migration provides a conservative estimate for the time of vertical migration. Although the top of the plume has low gas saturation, it propagates with a velocity close to the theoretical maximum. The bottom of the plume flows significantly more slowly at a higher gas saturation. Due to local heterogeneities, the plume can break into parts. Individual plumes also can coalesce and from larger plumes.

The analytical results are applied to studying carbon dioxide flow caused by leaks from deep geological formations used for CO2 storage. The results are also applicable for modeling flow of natural gas leaking from seasonal gas storage, or for modeling of secondary hydrocarbon migration.
Remotely Operated Platforms: Fact, Fiction, or Future
Authors: Levett B. A.
Published: December 2007

Remote operations technology is currently being successfully applied to the finance and transportation industries as well as the military. Closer to home in the oil and gas industry, remote operations have been applied to unmanned platforms, subsea equipment and satellite wells. The potential for remote operations is significant for offshore platforms, but it is imperative to separate fact from fiction. It is a common misconception to believe that all human interactions at offshore platforms can be eliminated. The potential is bigger than can be imagined today but not to that absolute degree. A pilot study was performed to determine what the risks and rewards were for implementing remote operations on several platforms in the Norwegian sector of the North Sea. Activities such as remote equipment monitoring, use of a centralized control room, specialists serving multiple platforms and campaign maintenance planning were assessed for impact on operating expenses (OPEX), functionality, reliability and safety. Reward potentials included reduction in OPEX, reduction in offshore personnel, less lost production and improved safety.
Real-Time Wire Management System Improves Reliability and Efficiency in Slickline Service Operations
Authors: De Jesús O. , Mineo R. , Foster J. C. , Hamid S.
Published: December 2007

The technological enhancements, new tools, versatility, and cost efficiency of slickline services have increased its usage considerably in the last decade. However, an efficient method to capture the integrity of slickline wire prior to its use has not been available until recently. This paper will discuss a new Real-Time Wire-Management System that has been developed to predict the used life of the wire in slickline operations. The system uses a general wire model to detect fatigue failure in the wire. The model results are accumulated for the whole life of each drum of wire, and then, when the use life exceeds predetermined levels, the operator can remove the slickline tool and can make appropriate changes to the wire. A specified amount of line can be cut off to move the bending point to a new location, or the line can be reversed, extending the life of the whole unit by moving the operation to wire that was located previously at the core of the drum. Finally, the system can help the operator determine when a drum of wire should be discarded completely. Field applications have shown that this system can result in enhanced reliability in slickline operations and that cost savings from reductions in catastrophic operational events can be significant.
Complete Decision-Tree Analysis Using Simulation Methods: Illustrated With an Example of Bitumen Production in Alberta Using Steam Injection
Authors: Laughton D. , Joe G. , Paduada M. , Samis M.
Published: December 2007

In September 2003, the SPE held a workshop on the future of asset valuation in corporate asset design and selection process. One suggestion that came out of the workshop was that methods should be developed that will allow the use of decision tree analysis not only in the exploration and appraisal phases of the asset life cycle, but throughout the cycle, and in such a way that the decisions to be analysed are made not only in response to the resolution of geological uncertainty but also in response to the resolution of price and other commercial uncertainty.

This will require a significant expansion of the computational technology available to deal in decision tree analysis with complex policy spaces in the face of complex structures of underlying uncertainties.

Work has been gong for several years in financial markets to deal similar issues using different subtle combinations of simulation and optimisation methods. Two of these combinations the Longstaff Schwartz method and the stochastic programming method have been applied recently to valuations in the mining industry in situations that are analogous to those faced by the upstream petroleum industry.

In this paper, we show how the Longstaff-Schwartz method, as adapted for use in a mining context, may be applied to the analysis of decision-making and value in the development of a bitumen deposit in Alberta using steam injection, where the underlying uncertainties are price movements in the bitumen produced and the natural gas used to produce the steam, and technological and geological uncertainties in the production and cost profiles. The analysis is complicated by the fiscal regime that brings to bear at each time the past price history through a particular form of ring-fenced resource rent royalty.