bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil Production Gains for Mature Steamflooded Oil Fields Using Propane as a Steam Additive and a Novel Smart Horizontal Producer
Authors: Rivero Jose A. , Mamora Daulat D.
Published: December 2007

We have conducted an experimental scaled model study to investigate the feasibility of two methods aimed at improving oil production from mature heavy oil fields. The first method involved the use of propane as a steam additive (propane:steam mass ratio of 4:100 was used in the study). The second involved the use of a novel well system consisting of a vertical injector and a smart horizontal producer. To minimize steam over-ride, the smart horizontal producer was divided into three sections, the section furthest from the injector being opened only after steam had broken through in the first two sections. The 16 in. × 16 in. × 5.6 in. physical model was scaled to present conditions in the San Ardo field in California and crude oil from the same field was used for the tests. The sides of the model consisted of 0.75 inch thick Teflon sheets to minimize heat loss, while the top and bottom consisted of 0.125 inch aluminum sheets to maximize heat conduction to the over- and under-burden. The physical model was placed in a pressure jacket containing nitrogen that provided an overburden differential pressure of about 20-40 psi during the runs. Superheated steam at 190-210°C was injected at 48 cm3/min (cold water equivalent) while maintaining the flowing pressures in the production wells at 50 psig. Liquid samples from each producer in the model were collected and treated to break emulsion and analyzed to determine water and oil volumes.

Main results of the study may be summarized as follows. First, for the vertical well system, addition of propane accelerated oil production by 53% and increased ultimate oil recovery by 7% of original oil-in-place (OOIP) when compared to pure steam injection. Second, use of the smart horizontal well system increased ultimate oil recovery to 49% OOIP compared to that obtained with the vertical well system (42% OOIP).
Fluid Flow in a Fractured Reservoir Using a Geomechanically-Constrained Fault Zone Damage Model for Reservoir Simulation
Authors: Paul Pijush , Zoback Mark , Hennings Peter
Published: December 2007

Secondary fractures and faults associated with larger, reservoir scale faults affect both permeability and permeability anisotropy and hence may play an important role in controlling the production behavior of a faulted reservoir. It is well known from geologic studies that there is a concentration of secondary fractures and faults in a damage zone adjacent to larger faults. Because there is usually inadequate data to incorporate damage zone fractures and faults into reservoir simulation models, in this study we utilize the principles of dynamic rupture propagation from earthquake seismology to predict the nature of fractured/damage zones associated with reservoir scale faults. We include geomechanical constraints in our reservoir model and propose a workflow to more routinely incorporate damage zones into reservoir simulation models. The model we propose calculates the extent of the damage zone along the fault plane by estimating the stress perturbation associated with dynamic rupture propagation. Fractures created by the stress pulse accompanying rupture propagation enhance permeability along reservoir scale faults in both the horizontal and vertical directions. We calibrate our modeling with observations from a number of studies and show that dynamic rupture propagation gives a reasonable first order approximation of damage zones in terms of permeability and permeability anisotropy in order to be incorporated into reservoir simulators.
A Unique Methodology for Evaluation of Multi-Fractured Wells in Stacked-Pay Reservoirs Using Commingled Production and Rate Transient Analysis
Authors: Manrique J. F. , Poe B. D.
Published: December 2007

We present a unique methodology designed for evaluation and optimization of multi-fractured wells in stacked pay reservoirs using commingled production. The specialized diagnostic procedures are based on rate-transient analyses, and uses historical production data (rates and cumulative) and the results from production logs to; 1) determine the flow rates for each individual stage in a multi-fractured well, 2) apply rate-transient solutions that use rate-normalized-pressures and superposition-in-time to evaluate response accordingly to the fracture flow periods, 3) estimate reservoir and fracture effective properties and 4) evaluate the completion efficiency.

The field examples presented in the paper, demonstrates the application of the production optimization methodology in practice. The approach permits quantification of the reservoir and fracture properties on a layer-by-layer, or frac stage-by-stage, by evaluating the production well history as an extended drawdown and in combination with direct physical measurements of the flow rates and flowing pressures. Such a unique procedure provides a great advantage since parameters such as; permeability (keffective), fracture length (Χf,effective), conductivity (kfbf)effective and dimensionless conductivity (CfD or FCD) can now be obtained for each individual fracture stage. In addition to the effective properties, the methodology allows for estimation of the drainage area and skin for unfractured zones and fracture half-length and conductivity for the hydraulically fractured reservoir layers.

The methodology is applicable to all types of reservoirs, however most of our field experience has taken place in the evaluation and optimization of stacked-pay tight permeability reservoirs and low conductivity fractures where other forms of conventional reservoir characterization techniques are technically difficult and/or cost-prohibitive.

The optimization methodology allows evaluation of the fracture performance efficiency in terms of the reservoir response and contribution, identification of non-fractured zones, bypassed zones (zones without a frac), under-designed fractures, low conductivity values (and steps for improving it), re-fracturing candidates and identification of remaining well potential deliverability.
Cased-Hole Cleaning: Do Annular Velocity, Annular Coverage and Contact Time Equal Mud Removal?
Authors: Darring Michael T. , Foxenberg William E. , Niehaus R. Brad , Stein Tim W. , Miller David M.
Published: December 2007

Mud-to-brine displacement efficiency can be difficult to quantify. Metrics to determine the success or failure of the displacement operation have traditionally been based upon the clarity of the completion brine that follows the spacers, the interface volumes of mud and completion brine, a visual determination of the cleanliness of the drillpipe pulled from the hole, and the time and materials required to filter the fluid. Despite their widespread use, however, these factors may not adequately characterize the quality of displacements in critical wells. Opportunities for improvement are largely affected by how well the displacement process can be understood. This can be difficult with the few direct and indirect parameters used to evaluate mud-to-brine displacement quality.

The authors initiated a study of samples captured during displacement circulations to examine the effects of spacer properties, volumes, pump rate, and chemical concentration on mud removal. The laboratory analyses inspected return samples of mud, spacers, and displacing fluids from 27 cased-hole wellbore displacements of oil-based and synthetic-based drilling mud in the Gulf of Mexico.

Results from this study suggest that criteria such as annular coverage, contact time, and annular velocity of the wash spacer(s), which have become the basis for most displacement programs, although critical to overall efficiency, are not the primary agents of mud removal during a wellbore cleanup.

Data correlations between the volume of mud observed in the samples analyzed and certain spacer characteristics suggest that cased-hole cleaning, when defined as mud removal, is a function of the size of a viscous spacer relative to hole size. This observation should simplify the displacement design process.
Potential for Oil Shale Development in the United States
Authors: Biglarbigi Khosrow , Dammer Anton , Cusimano Jeremy , Mohan Hitesh
Published: December 2007

The development of domestic oil shale resources has regained significant attention in the past few years. Several factors have contributed to this, including high oil prices, emerging recovery technologies, increasing world demand for liquid hydrocarbons, and the continued decline in U.S. conventional oil production. In recent years, several initiatives have been taken by the Federal Government and the private sector to encourage the development of a domestic oil shale industry.

The United States has vast deposits of oil shale – Nearly 2.0 trillion barrels across the eastern and western states. The development of this massive resource, however, is constrained by a number of key factors including, but to limited to: (1) resource access, (2) technology, (3) economics, (4) environmental and regulatory issues, and (5) infrastructure.

A comprehensive analysis has been completed to address the development of this resource. The analysis is based on a representative sample (about 70 Billion Barrels) of Western Oil shale resource divided among multiple development "tracts." Four (4) production technologies were also considered. These technologies included emerging in-situ processes as well as traditional mining with surface retorting technology. Each development "tract" was screened for the potential application of each recovery technology. A detailed economic evaluation was conducted for each "tract" and the selected technology with consideration for development under alternative economics, environmental, technology, and socioeconomic options. The analysis indicated that with a concerted effort from industry, local, state, and Federal governments, the shale oil production potential could reach 2.4 million barrels per day (MMBbl/d) with substantial benefits to the local and national economy.
Methods for Incorporating Costs, Pricing, Gas Shrinkage and Transport Tariffs, NGL and Inert Revenues, and Working Interest in Gas Plants and LNG Projects into Reserves Estimates
Authors: McLaughlin John , Gouge Brad
Published: December 2007

This paper reviews some of the ways that pricing and costs; gas composition and usage; entitlement interests; project approvals; and reserves aggregation affect reserve estimates and methods for incorporating these parameters into reserve studies. Techniques are discussed from the perspective of both SEC (Securities and Exchange Commission) and SPE/WPC/AAPG/SPEE (Society of Petroleum Engineers; World Petroleum Council; American Association of Petroleum Geologists; Society of Petroleum Evaluation Engineers) reserve definitions under the Petroleum Resources Management System (SPE-PRMS). In the cases where the definitions are not explicit as to processes for incorporating the above-ground parameters, the authors briefly discuss issues to consider such as past guidance by the SEC and industry norms for interpretations of the definitions.

In general, the SEC and SPE/WPC/AAPG/SPEE agree in how to account for many of the commercial and non-reservoir parameters. Where the two sets of definitions most markedly diverge are: Application of commodity pricesTreatment of revenue and/or volumes of non-hydrocarbonsInclusion of fuel gas as reserves or as projected "sales gas"Inclusion of hydrocarbons recovered by unconventional means (i.e. mining and processing)Criteria used for differentiating gas re-injection versus injection and storageConsideration for the appropriate level of aggregation in summarizing reserves portfolios

SEC and SPE-PRMS definitions tend to agree on methodology and practice in the areas of: Sales reference points and pressure basisBooking dry versus wet gasInclusion of coal bed methane (CBM)Calculation of entitlement net interests for production sharing agreementsApproval levels required for a project to be classified as proved

The purpose of this paper is not to pass judgment on either the SEC or SPE-PRMS definitions but rather to provide a summary of the methods used to account for some of the more common commercial and non-reservoir related aspects that arise in reserve estimation.
Swellable Packers for Well Fracturing and Stimulation
Authors: Yakeley S. , Foster T. , Laflin W.
Published: December 2007

Reactive element packers (REPs), sometimes referred to as swelling packers or self-energizing packers, offer a simple solution for multiple-zone open-hole completions. These packers are run into the well and begin to swell when they come into contact with various wellbore fluids, with the typical fluids of choice being water- or oil-based fluids. As the packers swell, they seal off the annulus between the liner/casing and the open-hole wellbore to provide isolation between zones with different pressures, or to simply shut off flow in the annulus and prevent migration of fines along the wellbore.

As REP technology makes its mark in zonal isolation, application of the technology for fracturing and well stimulation is beginning to be explored. REPs used for frac'ing and stimulation offer a simplified method of breaking the desired zone into smaller sections without adding the cost and complexity that may result from using the traditional cement and perforating methods.

This paper will discuss this new application for REPs. Functionality will be discussed, as will possible advantages and disadvantages of using the REP for well stimulation and fracturing. Key packer parameters will be reviewed to help demystify a seemingly infinite number of sizing possibilities. Then, initial testing to verify and validate the packer for this application will be discussed. Finally, this extensive test data will then be shown to validate a complex mathematical prediction model used to determine the REP's capabilities.
Monitoring SAGD Steam Injection Using Microseismicity and Tiltmeters
Authors: Maxwell S. C. , Du J. , Shemeta J. , Zimmer U. , Boroumand N. , Griffin L. G.
Published: December 2007

A combination of microseismic and surface deformation monitoring with an array of tiltmeters was used to monitor the warm-up phase of a SAGD well pair. A sequence of microseismic events was recorded with signal characteristics suggesting deformation associated with thermal expansion of the wellbore, in addition to events apparently associated with induced fracturing in the reservoir. Integration of the microseismic data with volumetric strain, inverted from the measured surface deformation, indicates a discrete deforming region near the toe of the well. The volumetric strain also shows another region near the heel of the well, although the area is too far from the microseismic observation well for any associated microseismicity to be recorded. The central portion of the well pair did not have significant deformation, indicating poor steam conformance during this warm-up phase. A comparison of the temporal response of the microseismic deformation with the surface uplift, suggests a lag between periods of accelerated seismic deformation followed by an associated period of accelerated uplift a few days later. This timing suggests the creation of a fracture network and related seismic deformation, which then fills with steam and starts to expand over a period of a few days. In a related paper9, stress changes associated with the volumetric strain are used to examine potential geomechanical failure zones that match the observed locations of microseisms. Together the volumetric strain, computed stress changes, and failure zones could be used to calibrate a geomechanically linked reservoir simulator.
An Innovative Manganese Tetra-Oxide/KCl Water-Based Drill-in Fluids for HT/HP Wells
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Al-Majed A. A. , Menouar H.
Published: December 2007

Drilling Unayzah-B gas reservoir (shale and sandstone) in Saudi Arabia requires high mud density (± 95 pcf). To formulate this mud, calcium carbonate particles were used, because of their high acid solubility. However, when drilling the 5-7/8 inch hole, sticking occurred, which resulted in expensive fishing and/or sidetrack operations. To minimize these problems, barite was added with CaCO3 to reduce the amount of solids needed to formulate the drill-in fluid. However, barite is acid in-soluble and may cause formation damage. Formate drill-in fluids with low CaCO3 content were used to drill some wells in this reservoir, however these fluids are expensive and corrosive if their high pH values were not maintained in the field.

Saudi Aramco has developed drill-in fluids that are based on manganese tetra oxide particles to drill deep gas reservoirs. The properties of these (D50 = 1 micron), spherical shape, and high specific gravity (4.8 g/cm3) make them good weighting material compared to CaCO3 (2.78 g/cm3 and D50 = 10 micron) and BaSO4 (4.25 g/cm3 and D50 = 20 micron).

The main objective of this study is to discuss lab work that was performed to design water-based drill-in fluids using KCl/Mn3O4 at 95 pcf. A second objective is to compare the properties of the new fluid with two typical fluids that are currently used to drill Unayzah-B reservoir. The first fluid is KCl/BaSO4/CaCO3 and the second one is potassium formate/CaCO3. The experimental work included measuring the rheological properties, thermal stability, API and HT/HP filtration of the three drill-in fluids.

The results obtained showed that several polymers can be used to design KCl/Mn3O4 –drill-in fluids. The developed fluid had better thermal stability and filtration control compared to the drilling fluids that are currently used. This paper will discuss the results obtained and will demonstrate that the new fluid can save time and cost of drilling deep wells.
Network Approach for Optimization and Control of Intelligent Well Systems: Theory and Practice
Authors: Ajayi Arashi , Konopczynski Michael , Sukkestad Tor
Published: December 2007

Intelligent well systems are gradually gaining ground in the development of hydrocarbon assets. One of the reasons is the value added by the technology in maximizing production relative to conventional systems because of its flexibility in reacting to detrimental production conditions.

The maximization benefit is closely tied to a simple, consistent, robust and standardized optimization process. This paper describes a network optimization and control methodology that can be implemented in either a zonal compensation or distribution mode. In a compensation mode, the technique maximizes total well throughput of a specified fluid stream (oil or gas) in a multi-zone commingled intelligent well system by rewarding favorable zones and penalizing unfavorable ones. In zonal distribution mode, it is used to allocate rates to contributing zones based on predefined distribution factors.

The approach is similar to those used in resource allocation and dynamic programming. Unlike the gradient-based method, this approach does not require calculations of differentials. Instead, it uses historical zonal production, pressure/temperature data, and installed down-hole component properties to recommend new operating conditions for each zonal down-hole interval control valve (ICV). The analysis involves characterization of the zonal ICVs within the boundaries of the contributing reservoirs and specifying dynamic or static constraints for the well of interest. This analysis is then combined with existing zonal and total well data to predict an optimized operating condition for the zonal ICVs. The method can be used both in a reactive or proactive mode. It can also be used in a discrete or continuous flow process. The paper discusses the optimization and control process and provides two field cases.
Eliminating Buoyant Migration of Sequestered CO2 Through Surface Dissolution: Implementation Costs and Technical Challenges
Authors: Burton McMillan , Bryant Steven L.
Published: December 2007

Sequestration of CO2 in geologic formations will be part of any substantive campaign to mitigate greenhouse gas emissions. The risk of leakage from the target formation must be weighed against economic feasibilities for this technology to gain stakeholder acceptance. The standard approach to large-scale geologic sequestration assumes that CO2 will be injected as a bulk phase into a saline aquifer. In this case, the primary driver for leakage is the buoyancy of CO2 under typical deep reservoir conditions (depths > 2600 ft or 800 m). Investigating alternative approaches that utilize inherently safe trapping mechanisms can help to characterize the price of reducing the risk of leakage.

In this paper, we investigate a process in which CO2 is dissolved in brine prior to injection into deep subsurface formations. The CO2-laden brine is slightly denser than brine containing no CO2, so ensuring the complete dissolution of all CO2 into brine at the surface prior to injection will eliminate the risk of buoyancy-driven leakage. We examine the feasibility of dissolving CO2 at surface facilities and injection of the saturated brine. To estimate the costs of this process, we determine the capital costs for the additional facilities and compare them the capital costs for injecting bulk phase CO2. We also estimate the power requirements to determine the additional operating costs. The additional capital and operating costs can be regarded as the price of this form of risk reduction.

Comparing this alternative to the standard, we find that an additional power consumption of 3% to 8% of the power plant capacity will be required and the capital costs will increase by 34% to 44%. Brine is required at rates of millions of barrels per day, and in most applications this would be lifted from the target aquifer. The bulk volume of the aquifer is on the order of a hundred million acre-ft for reasonable power plant sizes (250MW to 1000MW) and for reasonable injection periods (30–50 years). Although this alternative results in higher costs, surface dissolution may be attractive where the costs of monitoring or insuring against buoyancy-driven CO2 leakage exceed these additional costs.
Improved Production and Process Optimization Through People, Technology, and Process
Authors: Sagli Jan Richard , Klumpen Hans Eric , Nunez Gustavo , Nielsen Frank
Published: December 2007

A joint venture Production & Process Optimization project between Statoil and Schlumberger is targeting two distinct areas: ■Improved reservoir management to optimize the reservoir performance over the life of the field.■Production optimization of the intelligent wells, production network and process facilities on a day-to-day basis. This is achieved through development of tools, methodologies and workflows.

In order to support the change management process, a prototyping process has been developed for surveillance workflow development and deployment. The dynamic prototyping process allows a bottom-up development of workflows starting from data conditioning and reconciliation up to optimization and control. These different automation modes for provided workflows go along with deriving information and ultimately knowledge from production process data in order to improve decision making processes.

A demonstration project will concentrate primarily on the Water Alternate Gas (WAG) cycle optimization process, which has been specified together with the asset team, and will describe how the workflow supports production optimization.

The solutions are successively tested together with the Snorre B asset. Results from the demonstrator, change management issues and the concept of full integration of all decision making loops into a workflow framework will be presented in the paper. During the testing not only the application of the software solution was evaluated as well the impact on the organization and how changes in proposed work processes improved the inter domain collaboration within the team.

The project has demonstrated successfully that three key areas have to be addressed simultaneous: ■Change Management procedures in order to introduce the developed workflows and software tools as early as possible■Necessary software tools for providing a workflow oriented framework for production optimization■Prototyping workflows and implementation through demonstration and pilot projects as well as permanent facilitators working with asset teams
Where Will the Next Generation of Petroleum Engineers Come From? Disturbing Observations From a Texas Oil Town
Authors: Schrader S. M. , Balch R. S. , Bunnell D.
Published: December 2007

There is a concern in the oil and gas industry about an imminent shortage of professionals. Many factors contribute to this expected staff shortage, including large numbers of oil workers nearing retirement age, worker diasporas during lean times, lack of job prospects for students during the 80's and 90's and the resulting decline in enrollment in petroleum engineering programs. Currently, the industry is recruiting aggressively, offering high salaries; many college students have jobs arranged by their junior year. It might be expected that students would be enticed to prepare for careers in the oil and gas industry, especially in areas like west Texas, where the oil industry contributes enormously to the economy, oil jobs are plentiful, and are salaries high. However, a discussion with college bound juniors and seniors at Odessa High School in west Texas revealed that very few intended to pursue oil and gas-related careers. This disturbing result led to the authors to develop a survey to evaluate high school students for their interests in, and attitudes about, the industry.

Survey questions cover the students' overall view of the industry, their impressions of industry technology, their desire to work in industry, factors affecting that desire, and general demographic data

Initial observations indicate that students believe the oil and gas industry is low-tech, jobs are highly paid but unreliable, oil and gas will not be major energy resources in the future, and that a high school education can earn an employee close to what degreed employees earns, diminishing the value of a petroleum degree.
Workover Successes in Deviated Wells Using Multispinner Production Log Data
Authors: Horner Steve , Grayson Steve , Elliot Burt , Sandoval Alex , Alban Patricio
Published: December 2007

This paper gives the details and results of a successful workover program conducted offshore California in 2006. The wells are highly deviated, producing oil, gas, and water from natural fractures. Analysis from a new production-logging tool, coupled with geologic data and a new artificial lift system design, were used to optimize production.

The new production logging tool uses multiple probes to characterize complex flow profiles and quantify fluid entries in horizontal and deviated wells. Tractor conveyance while logging was required on one of the wells. Previous workovers in the area, using older technology log data, had shown variable results. More aggressive water control techniques were employed in one well, where a fault intersection caused a major water influx in the middle of the perforated section. The water productive intervals were squeezed and the surrounding oil zones re-perforated and stimulated, resulting in decreased water and a 12-fold increase in oil production. In another well, analysis indicated that a bottom-water shutoff and conversion to an electrical submersible pump would optimize this high-productivity index well. The results confirmed this, however the gas/liquid ratio increased and the pump began to gas lock, causing the well to produce below its maximum potential. Using the production log data, engineers landed the pump below the main gas producing zone to allow gas to vent directly up the casing. A redesigned ESP with the new helicoaxial gas handling pump and downhole sensor were utilized to optimize bottomhole flowing pressure and increase oil production by more than 200 BOPD.

Pasting the production logs along the well trajectories in our 3D geological model led to interesting conclusions about the sources of water production. Excessive water production correlated with perforated zones located at the intersections with fault surfaces. This graphical technique could be used by other operators of fractured reservoirs.
Evidence of a Horizontal Hydraulic Fracture at Depth Due to Stress Rotations Across a Thrust Fault
Authors: Maxwell S. C. , Zimmer U. , Gusek R. , Quirk D.
Published: December 2007

Microseismic imaging of a hydraulic fracture stimulation showed significant fracture reorientation across a thrust fault. Fracture orientations were identified through a combination of alignment of event locations, polarization of the seismic waves and injection details. Stimulation below the fault indicated a near horizontal fracture geometry. Above the fault, a near vertical fracture geometry was observed. A change in fault orientation was supported by differences in the microseismic signal characteristics and the treatment injection data. This difference in fracture geometry was attributed to rotations in the direction of minimum principle stress, which is consistent with observed differences in the injection pressures. The fracture reorientation suggests a significant difference in the stimulated permeable pathways for sands above, compared to below the fault.
Introducing New API/ISO Procedures for Proppant Testing
Authors: Kaufman Phillip B. , Brannon Harold D. , Anderson Robert W. , Ziegler Mark , Neves Aidner R. , Parker Mark A. , Abney Kathy , Cortes Gabriel Warwick Kerr de Paiva , Joyce Sara , Penny Glenn S.
Published: December 2007

In 2001, the International Organization for Standardization (ISO) and American Petroleum Institute (API) formed a new committee to write procedures for measuring the properties of proppants used in hydraulic fracturing. API Recommended Practices (RP) for testing of proppants are generally "reviewed and revised, reaffirmed, or withdrawn at least every five years" in accordance to API instructions. The last Recommended Practice was published in December 1995. The committee was charged with re-writing API RP 56, 58, and 60 relating to sand as a proppant, gravel packing, and high strength proppants, respectively. This new document, ISO 13503-2 "Measurement of Properties of Proppants Used in Hydraulic Fracturing and Gravel-Packing Operations" is a standard. Any company may follow these procedures and state on their published data that they followed ISO procedures to generate the specifications of their product. Several changes have been made to the Recommended Practices, and the goal of this paper will be to highlight these changes, and to discuss the potential impact on the proppant industry. In 2003 a second committee was formed to write procedures on measuring long term conductivity of a proppant pack. The industry was using for years a procedure based on API RP 61 "Recommended Practices for Evaluating Short Term Proppant Pack Conductivity" 1989, which is an obsolete document. Roughly a dozen facilities worldwide are running long term conductivity tests, all slightly different. Recent advances in technology have been incorporated in this standard to increase the accuracy of the results, and to standardize the equipment and testing procedures. The new standard is ISO 13503-5 "Procedures for Measuring the Long-Term Conductivity of Proppants".

These two new procedures will enable users to evaluate and to compare proppant characteristics under the specifically described test conditions for use in hydraulic fracturing operations. They are not designed to provide absolute values of proppant conductivity under downhole reservoir conditions. Test data has shown that time, elevated temperatures, fracturing fluid residues, cyclic stress loading, embedment, formation fines, and other factors will further reduce proppant pack conductivity.
Real-Time Diversion Quantification and Optimization Using DTS
Authors: Glasbergen Gerard , Gualtieri Dan , Trehan Rakesh , Van Domelen Mary , Nelson Micky
Published: December 2007

In matrix treatments, optimum placement of the injected fluids is essential. Over the years, several diversion techniques have been applied to obtain a desired fluid distribution. The latest developments in the application of distributed temperature sensing (DTS) during matrix treatments to monitor temperature profiles along the wellbore in real time show that fluid distribution can be quantified.

This paper discusses the application of DTS to quantify the effectiveness of diversion agents. Quantification of fluid distribution makes it possible to determine the flow distribution both before and after a diverter stage so that the diversion effect can be evaluated.

Knowledge of the diverter effect will lead to better understanding of the diversion process and subsequently to optimization of future treatment designs. Ultimately, use of real-time quantification of the effect of diversion will lead to the development of real-time optimization itself. In real-time optimization, the results of a diverter stage will be used to adjust the next diverter stage to optimize placement.

The post-treatment analysis of the temperature profiles showed that flow distribution can be quantified both before and after a diverter stage. Based on the observations, the decision was made to develop a diagnostics tool that can be used in real time and will enable real-time quantification.

The novel approach of using the diagnostics tool in combination with DTS during matrix acid treatments will help to further optimize diversion treatments. This optimization is both an optimization during the treatment and an optimization of diverter stages in future treatments.
On IFT Measurements to Estimate Minimum Miscibility Pressures
Authors: Jessen Kristian , Orr Franklin M.
Published: December 2007

Measurements of the interfacial tension of mixtures of a reservoir fluid and injection gas at various pressures have been proposed as an experimental method for predicting the minimum miscibility pressure (MMP) in an experiment called the vanishing interfacial tension (VIT) technique. In this paper we analyze the accuracy and reliability of the VIT approach based on phase equilibrium and slimtube experimental observations and equation of state calculations of the behavior of VIT experiments for the same systems.

We consider 13 gas-oil systems for which phase equilibrium and density data and slimtube measurements of the MMP are available. We show that tuned equation of state characterizations using 15-components to represent the gas/oil systems yield calculations of phase compositions and densities and calculated MMPs that reproduce accurately the experimental observations. We assume that IFTs can be calculated with a parachor expression, and we simulate the behavior of a series of VIT experiments with different mixture compositions in the VIT cell. We show that compositions of mixtures created in the VIT cell are not, in general, critical mixtures and that calculated estimates of the MMP obtained by the VIT approach depend strongly on the composition of the mixture used in the experiment. We show also that those MMP estimates may or may not differ significantly from values obtained in slimtube displacements. Fortuitously chosen mixture compositions can result in VIT estimates that agree well with slimtube MMPs, while for other mixtures, the error of the estimates can be quite large. In particular, we show that errors in the VIT estimate of the MMP are often large for gas/oil systems for which the first contact miscibility pressure is much larger than the slimtube MMP.

We conclude, therefore, that the VIT experiment is not a reliable single source of information regarding development of multicontact miscibility in multicomponent gas/oil displacements.
New Remote Collaboration Models for Oil and Gas
Authors: Matson J R , Krome J D , Chmela W
Published: December 2007

The Intelligent Oilfield (IOF), also known as the Digital Oilfield of the Future (DOFF), encompasses a collaborative environment (CEs) for communication, data collection, reporting and monitoring, and knowledge & information sharing. These environments, or physical workspaces, are intended to help people make more informed decisions and to take the appropriate actions across the enterprise. In addition, it enables alignment, focus, and a common understanding to help prioritize opportunities.

Innovations in various collaboration technologies are helping companies to make the intelligent oilfield a reality. One of the key implementation components currently attracting attention is the collaboration or remote surveillance center – a high-tech, communications, visualization, and audio-enhanced monitoring or control room. Although the facility is intended to create an atmosphere for improved communications, multifunctional work, and a means to help eliminate organizational barriers, the center itself is only the physical manifestation of the desired spirit of richer and increased human interaction.

There are currently two differing philosophies for the implementation of these centers – an asset-based center that services a single asset and a central hub that services multiple assets. Each approach has its own particular merits and potential pitfalls. Although there is no single right answer, certain considerations are recommended before construction begins that could assist in determining the most appropriate approach for the given circumstances. Factors such as corporate culture and employee skill base can have a huge impact on the success of the final choice. Without such an evaluation, many efforts will continue to be burdened or opportunities will be deferred or lost.
Wellbore Stability Considerations for Drilling High-Angle Wells Through Finely Laminated Shale: A Case Study From Terra Nova
Authors: Gallant Chris , Zhang Jianguo , Wolfe Christopher A. , Freeman John , Al-Bazali Talal , Reese Mike
Published: December 2007

High angle wells drilled into finely laminated shale are often found to be less stable than comparable wells drilled into non-laminated rock. This can be attributed to a variety of factors including, but not limited to, well trajectory, the in-situ stress field, rock strength anisotropy, shale reactivity issues, chemical imbalances between the drilling fluid and shale pore fluid, and many others. However, due to the lack of available data some of these mechanisms are difficult to quantify and therefore are typically not accounted for during well planning. This can result in significant wellbore instability issues that substantially elevate drilling operation costs.

In this paper, a comprehensive approach to account for many of these wellbore instability mechanisms is outlined. A plane-of-weakness model is utilized to account for the effects of weak bedding planes and other discontinuities. The model uses parameters that are obtained by curve fitting triaxial strength test results conducted at various angles with respect to bedding. Additionally, traditional mechanical and chemical effects were also addressed and incorporated into the pre-drill model to assist in well planning. The model was then implemented at the Terra Nova field for the case of a highly deviated wellbore drilled through finely laminated shale nearly parallel to bedding.

Real-time monitoring of measurement and logging while drilling data was key to identifying the unstable sections so that the root cause of instability could be diagnosed. The appropriate remedial action was then applied and wellbore instability problems were mitigated.

Both mechanical and chemical borehole instability models were applied in a case history to evaluate the potential for wellbore instability. In particular, bedding-plane related and chemically-induced instability were addressed and overcome through comprehensive modeling and the deployment of modified operational procedures.
Evaluation of Low-Resistivity-Pay Deepwater Turbidites Using Constrained Thin-Bed Petrophysical Analysis
Authors: Bastia R. , Tyagi A. , Saxena K. , Klimentos T. , Altman R. , Alderman S. , Bahuguna S.
Published: December 2007

A novel methodology has been developed to evaluate low resistivity pay reservoirs in very thin, laminated sand-shale sequences. This technique combines information from both high and low resolution logs to model the petrophysical properties of thin bedded formations. The result is a set of modeled high resolution logs that can be used to yield more accurate estimations of porosity, water saturation and permeability.

A high resolution and a low resolution log response are selected and binned into discrete lithofacies. The average low resolution log responses are statistically calculated for each lithofacies. An initial model is generated by using the high resolution lithology index to select the corresponding low resolution response for each lithofacies, resulting in a set of high resolution logs for each input log. By applying a corresponding vertical response filter to the high resolution log, a synthetic log is created which can be compared to the original. A minimization technique is used to adjust the high resolution responses such that the synthetic and actual logs agree. Since there are an unlimited number of high resolution logs which could result in the same synthetic response, the process is constrained using limits defined for each lithofacies. Evaluation of hydrocarbons in place is then performed on the resulting model.

This paper documents examples in deep-water turbidite reservoirs where thin beds on the scale of a few centimeters were evaluated using this technique. The observations were consistent with core data where this was available. Thin bedded silt and shale laminae had a disproportionate effect on standard resolution measurements due to the abundance of montmorillonite clay which caused elevated neutron and suppressed resistivity responses. The constrained thin-bed analysis yielded considerable enhancement of hydrocarbons in place compared with the evaluation using only standard resolution measurements.

Thin bedded laminated reservoirs occur in many hydrocarbon provinces. The technique described in this paper provides an alternative method for evaluating these formations, helping to reduce reserves uncertainty during a time where accurate reserves evaluation continues to receive high attention.
Effect of Well Variables on the Performance of Chemical, Jet, and RCT Tubing Cutters
Authors: Jurgens M. S.
Published: December 2007

An analysis of 72 tubing cuts made during Shell deepwater workovers in the Gulf of Mexico was completed to determine the effect of well variables on the cutting performance of chemical, jet, and radial cutting torch cutters.

An initial pre-study analysis indicated that cutting success was only 65%, 50%, and 77% for the chemical, jet, and radial cutting torch cutters, respectively. It was found that some cutting failures could be attributed to specific causes, such as heavy paraffin in the well, improper detonation, low-pressure tool leaks, exceeding tool pressure limits, and improper tool gas ventilation; however, other failures did not have any apparent cause. These remaining cuts were analyzed against specific well variables to look for trends that may indicate the cause of failure.

It was determined that chemical cutter success in CaBr2 completions fluids was much lower than all other fluids combined. Specifically, cuts in bromide fluids accounted for 71% of the total number of failed cuts, but only comprised 32% of total attempted cuts. Further investigation indicated that bromide fluids may react more violently with the bromine trifluoride acid than the other types of completion fluids used. From this analysis, it is believed that less acid will be available to sever the pipe wall when cutting in bromide fluids.

Additionally, it was found that placing the pipe in tension significantly increased cutting performance. No other significant correlations were found to other well variables.
Multiscale Methods for Modeling Fluid Flow Through Naturally Fractured Carbonate Karst Reservoirs
Authors: Popov P. , Qin G. , Bi L. , Efendiev Y. , Ewing R. , Kang Z. , Li J.
Published: December 2007

Modeling and numerical simulations of Carbonate Karst reservoirs is a challenging problem due to the presence of vugs and caves which are connected via fracture networks at multiple scales. In this paper we propose a unified approach to this problem by using the Stokes-Brinkman equations which combine both Stokes and Darcy flows. These equations are capable of representing porous media (porous rock) as well as free flow regions (fractures, vugs, caves) in a single system of equations. The Stokes-Brinkman equations also generalize the traditional Darcy-Stokes coupling without sacrificing the modeling rigor. Thus, it allows us to use a single set of equations to represent multiphysics phenomena on multiple scales. The local Stokes-Brinkman equations are used to perform accurate scale-up. We present numerical results for permeable rock matrix populated with elliptical vugs. Both constant and variable background permeability matrices are considered and the effect the vugs have on the overall permeability is evaluated. Fracture networks connecting isolated vugs are also studied. It is shown that the Stokes-Brinkman equations provide a natural way of modeling realistic reservoir conditions, such as partially filled fractures.
Evaluation of Infill Drilling Opportunities in Lekhwair Field, Oman
Authors: Jayanti Shekhar , Chopra Anil , Giordano Ronald M. , Yuan Hua , Tie Hongguang , Suleimani Ali , Gheithy Ali , Edwards Clement
Published: December 2007

This paper presents an evaluation of infill drilling opportunities in a mature waterflood. Different infill drilling configurations for increased oil recovery are compared using a ranking scheme. The field has been on production since 1976. The field has a complex development history, with periods of primary recovery, shut-in, 5-spot, inverted 9-spot, and direct line-drive waterflood. The field is currently undergoing a linedrive waterflood. The challenge is to find new infill drilling opportunities and determine optimal well spacing to maximize oil production.

Traditional infill drilling evaluations either use empirical techniques based on ad-hoc esimates of drainage areas or reservoir simulation of the field-level benefits of an infill drilling program. The former approach ignores the impact of reservoir heterogeneities while the latter approach makes it difficult to evaluate the contribution that each infill well makes to the field-level benefit. Our approach isolates the impact of each infill well and provides a fast and novel methodology to evaluate the incremental benefit while accounting for reservoir heterogeneity, well conditions, pattern configuration, injection rates, and voidage replacement ratio. This type of analysis helps optimize the number of wells to be drilled and at the same time leads to increased oil recovery through better waterflood management.

Streamline analysis was used to identify dead spots and regions of unswept oil in a part of the field. A novel waterflood management workflow was used to evaluate new infill well configuration strategies to increase oil recovery and better manage the waterflood. Optimization studies were also conducted to minimize the number of wells with the right combination of injectors and producers and obtain significant incremental benefits. Work is underway in the field to implement these recommendations and early results point to the success of this approach.

This paper presents a novel approach for evaluating the impact of infill drilling. The marginal utility of each infill well is calculated and then is used to optimize the number of wells and maximize oil recovery. The approach presented can be used to quantify the impact of infill drilling and increase oil rate and recovery in similar reservoirs.