bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Friction Reducers for High-Density Brines and Their Application in Coiled Tubing at High Temperatures
Authors: Ke M. , Qu Q. , Stevens R. F. , Bracksieck N. , Price C. , Copeland D. 
Published: December 2007

AbstractHigh density brines can provide increased hydrostatic pressure when used as cleanout fluids in coiled tubing operations. Due to the high viscosities of brines and the small diameter of coiled tubing, friction pressure loss will offset the additional hydrostatic pressure exerted by high density brines and lead to serious limitations in job design. One solution is to apply a friction reducer. Most commercial friction reducers are designed for water or low density fluids; their solubility and dispersion characteristics in high density brines are usually not acceptable. Additionally, high salt content and low free water in brines can diminish the effectiveness of a friction reducer. Many papers have been published on friction reducers in water or low density fluids in straight tubing and coiled tubing, but few have addressed friction reducers in high density brines. Evaluating a friction reducer normally requires full-scale flow loop testing, which requires a large volume of brine and prevents thermal evaluation of friction reducers.This study used a newly designed coiled small-diameter tubing (CSDT) flow loop to evaluate the properties of friction reducers in high density brines. The study evaluated two conventional friction reducers in brines including NaCl, CaCl2, NaBr, and CaBr2 with densities from 10.0 to 14.2 ppg. The study presents results from both CSDT and full-scale flow loop tests and demonstrates that the CSDT flow loop is a simplified and effective setup that can qualify friction pressure loss in tubing and evaluate the effectiveness of a friction reducer in high density brines. Heat-aging tests also investigated thermal degradation of friction reducers in brines. The tests can eliminate some commonly used friction reducers for high temperature applications due to thermal degradation. A case history is presented which successfully applied a friction reducer in an 11.0 ppg CaCl2 brine for a coiled tubing cleanout at 400°F.
Intelligent Electronic Firing Heads: Advancements in Efficiency, Flexibility, and Safety
Authors: Goodman K. R. , Bertoja M. J. , Staats R. J. 
Published: December 2007

AbstractFiring heads are widely used for initiation of perforating guns and other pyrotechnic devices in non-wireline deployments. For the last 25 years, these devices have been overwhelmingly based on hydraulic and mechanical designs; typically they require the shearing of pins through pressure activation or drop bar release. Features such as firing delays or multiple pressure cycle operation have been developed with additional complexity. These mechanical systems are less precise in operation due to tolerances and are also influenced by variations in downhole conditions such as temperature, pressure, and duration. Contrarily, electronic firing heads can be immune to these variations, while offering improved accuracy and control. No longer are high pressures needed to activate a firing head, instead low pressure coded command sequence of pulses can be used for communication. Delays can be extremely precise and simply programmed into the operation. The option to abort firing is also available, as well as the ability to measure and record dynamic pressures during the perforating event. Electronic firing heads have become the preferred solution due to the benefits they provide in safety, reliability and flexibility across numerous applications and deployments around the globe.The ability to use a low pressure coded command for initiation has many advantages in operational logistics and safety. For slickline applications the firing process is controlled using line tension pulses; this combination provides a reliable solution with simplified deployment while still giving the operator control of the initiation process.This paper describes the operation of an advanced electronic firing system and provides a number of case studies demonstrating the benefits for TCP, coiled tubing, and slickline perforating operations.
Successful Flow Profiling of Gas Wells Using Distributed Temperature Sensing Data
Authors: Johnson D. , Sierra J. , Kaura J. , Gualtieri D. 
Published: December 2007

AbstractDistributed temperature sensing (DTS) coupled with a temperature-pressure simulator has been used successfully to determine flow profiles from multilayered commingled reservoirs in production gas wells. This technology has enabled quantitative individual-layer contributions to gas flow rates and main water entries to be determined, which in turn, has helped engineers to evaluate production conditions, track individual layer recovery, identify problem zones, and plan remedial actions.DTS technology uses fiber-optic cables to measure continuous temperature profiles along the entire wellbore without any cable movement.The real cases presented here include producing gas wells ranging from very low-permeability, hydraulically fractured tight reservoirs to high permeability sands with production rates from one (1) to tens of MMscf/d and over 50 layers per well at depths between 7,000 to 15,000 ft.The analyses have shown that some of the key parameters required to obtain representative flow profiles using DTS can be extracted from the flowing and shut-in DTS transient profiles.Those parameters, which are generally not available in conventional temperature logs, include: (i) geothermal profile; (ii) wellbore and near-wellbore Joule-Thomson effects, and (iii), thermal properties of fluids and formation. Non-producing, thick zones are particularly useful when calibrating partial flow rates and verifying fluid and formation properties.The flow-profiling model was built around an analytical-numerical, pressure-temperature simulator that predicts wellbore temperature profiles as a response to individual layer flow rates and sandface fluid-entry temperatures. An interactive error-minimizing technique was used to match the simulated temperatures with the actual DTS profiles.This paper also presents comparisons between the DTS-derived flow profiles and the traditional production logging tool (PLT) profiles as well as the value DTS can provide for multilayered gas-reservoir monitoring.
Stochastic History Matching and Data Integration for Complex Reservoirs Using a Wavelet-Based Algorithm
Authors: Sahni I. , Horne R. N. 
Published: December 2007

AbstractThis work develops a generalized wavelet-based methodology for stochastic data integration in complex reservoirs models. This is an extension of our earlier work for simpler reservoir descriptions (Sahni 2003; Sahni and Horne 2005, 2006). A single history-matched reservoir permeability model is combined with a stochastic geological description to obtain multiple equiprobable reservoir descriptions using wavelet transforms of the parameter distribution (permeability). In this paper the algorithm has been extended and generalized to be usable with commercial reservoir simulation software and to enable handling of complex three-dimensional models and production scenarios. We also conducted a study of sensitivity coefficient distributions, thresholding and averaging techniques, and a comparison of different Haar wavelet implementations.Wavelet coefficients of reservoir parameter distributions are decoupled into sets of history-matching and geologic coefficients and modified independently. Inverse transformation of these coefficients yields multiple reservoir model results, all of them matched to history. A significant reduction in time is obtained for stochastic modeling of reservoirs by use of this decoupling of production data and other parameters, since only a single history match is required.Thus the proposed algorithm addresses the issue of stochastic modeling of complex reservoirs by integrating all available sources of information. From a single history-matched model we obtain a set of distinct equiprobable reservoir models that can then be used to evaluate uncertainty and make future production predictions and reservoir management decisions.
CO2 Transport Mechanisms in CO2/Brine Coreflooding
Authors: Grigg R. B. , Svec R. K. 
Published: December 2007

Abstract
Concerns for the possible consequences of increased greenhouse gas emissions will undoubtedly increase carbon dioxide (CO2) injection into oil reservoirs for enhanced oil recovery (EOR) and probably into other geological formations for sequestration.1 The development of CO2 plumes and subsequent dissolution into formation brine are essential mechanisms in most sequestration scenarios and could aid in understanding long-term injectivity reduction in EOR WAG (water alternating with gas injection) projects. This paper describes laboratory tests on sandstone and carbonate core samples. Two types of displacement tests were performed; gas injection to a residual brine saturation with respect to gas, followed by brine injection to a residual gas with respect to brine. The level of CO2 saturation in the injected brine at reservoir pressure and temperature was varied from zero to over 90% saturation. Sandstone and limestone rock types were tested. This variation in CO2 saturation in the injected brine was to determine the effect on the CO2 saturation or plume size in the core. This information can be used in CO2-EOR-WAG projects and carbon sequestration into geological formations.
By injecting CO2 into brine-saturated Frio sandstone the brine saturation was reduced to 68–71% in each of five tests. In each test, over 90% of the reduction occurred with less than 0.33PV of CO2 injected, with very little additional brine production after 0.5PV of CO2 injected. During brine injection, CO2 production was equivalent to the rate expected from brine saturated with CO2 at the reservoir conditions. This indicates that for Frio core at high irreducible brine saturation at the tested flow rate (~6 ft/day), the CO2 plume was reduced through dissolution, not displacement. With increasing CO2 saturation in the injected brine, the brine volume required to remove (dissolve) the CO2-plume increased proportionally. Results will be used to aid in predicting injectivity in CO2-EOR-WAG operations and CO2 plume migration and dissolution in EOR and sequestration. The principle mechanisms for CO2 saturation reduction are identified.
Wellbore Cooling as a Means To Permanently Increase Fracture Gradient
Authors: Gil I. , Roegiers J. -C. , Moos D. 
Published: December 2007

Abstract
In recent years, several techniques have been proposed to increase the fracture gradient by inducing changes in the near wellbore region (Alberty and McLean, 2004; Sweatman, et al., 2004;Benaissa et al., 2005). This process, often called "wellbore strengthening", has most recently been implemented by adding specially designed proppant material to the mud before raising its pressure above the fracture gradient. The goal was to induce short tensile fractures in the vicinity of the wellbore wall which are prevented from propagating; thus, creating a "stress cage". However, this method has often proven ineffective in low permeability formations where mainly uncontrolled fracture propagation occurs.
The purpose of this paper is to propose and evaluate the use of wellbore cooling, in combination with more classical stengthening processes, to permanently increase the fracture gradient without the risk of circulation losses inherent in the "stress cage" method, as it is currently applied. This approach involves lowering the temperature of the drilling mud; thus, reducing the hoop stress at the borehole wall and then ‘setting’ the stress cage in the standard manner. Tensile cracks can then be induced at significant lower mud weights. Given the typical thermal conductivity properties of rocks,the tensile stresses induced by cooling (and consequently, the created fractures) will tend to be confined to the near wellbore region.
This work presents an evaluation of the effect cooling has on the stress profile of a "solid" material and compares it with a fully coupled thermoporoelastic solution. The results of such analyses may then be used to design a field application to test this novel idea.
Continuous Fracture Modeling of a Carbonate Reservoir in West Siberia
Authors: Pinous O. , Zellou Abdel M. , Robinson Gary , Royer Ted , Svikhnushin N. , Borisenok D. , Blank A. 
Published: December 2007

Abstract
The field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties of the matrix are generally negligible, and the production potential of wells is mostly associated with natural fractures and vugs.
The presented study was our first project in Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BKZ logs processing, 2) Spectral imaging and high-resolution inversion of the seismic data, 3) structural analysis of the field, 4) construction of the reservoir properties model, 5) construction of the fracture distribution model using the Continuous Fracture Modeling approach (CFM). A comprehensive description is available on a previous publication1.
The final geologic model served as a basis to select the locations for the new wells. The new locations were proposed in the zones with the most intensive development of a network of natural fractures (according to the model). The drilling was associated with significant losses of drilling mud that was an indirect indication of presence of significantly fractured zones. The wellbore image FMS that was recorded in the well, showed a good level of correspondence between the model forecast and the actual result. The well contains interval of numerous fractures and large vugs. Eventually, the well showed a good production results and currently is one of the best producers in the field.
As such, we recommend application of the described integrated approach for modeling complex fractured reservoirs in the other fields of Russian Federation.
Underbalanced Drilling In The Reservoir, An Integrated Technology Approach
Authors: Ramalho John 
Published: December 2007

Abstract
Shell is a major player in the Global deployment of Managed Pressure Drilling (MPD) technology to reduce drilling problems, minimize formation damage and improve reservoir management techniques.
The impetus is a recognition that most of the world's mature hydrocarbon reservoirs are in the lower end of the depletion cycle and an increasing number of horizontal wells are left with un-cemented completions. In addition, to access new untapped reserves, requires venturing into deeper water depths and the exploitation of deeper tight gas reservoirs, each with its own challenges.
This paper describes the process involving rigorous pre-screening, planning, execution and feedback of learning developed that enables fast implementation of underbalanced drilling (UBD) and integrated technologies into "Brown Field" areas and new business opportunities in "Green Field" development.
This begs the question; what is Managed Pressure Drilling technology and what is the relationship with underbalanced drilling?
The International Association of Drilling Contractors (IADC) defines Managed Pressure Drilling as "an adaptive drilling process used to precisely control the annular pressure profile throughout the well bore. The objectives are to establish the down-hole pressure environment limits and to manage the annular hydraulic pressure profile accordingly".
In a sense managed pressure drilling, covers all drilling, since management of pressure is the goal of all drilling activities. However, there is general industry agreement that Managed Pressure Drilling is an umbrella term that refers to drilling activities conducted in a closed loop system. Conventional overbalanced drilling sits at one end of the Managed Pressure Drilling spectrum and underbalanced drilling at the other end.
In conventional drilling, bottom hole pressure is managed by controlling the density of the drilling fluid to maintain well bore pressure profile above the pore-pressure throughout the well bore. Underbalanced drilling on the other hand, the well bore pressure profile is intentionally kept below the pore-pressure of all the exposed formations in the well bore. In between these two extremes are various techniques used to control the annular pressure profile and overcome constraints imposed as a result of the equivalent circulating density of the mud system. Seen from Shell's perspective, Managed Pressure Drilling is a basket of drilling techniques that can be adapted to solve drilling related problems, reduce formation damage and or dynamically characterize production reservoirs (while drilling) to enable improved reservoir management. It is also worthy to note that not all Managed Pressure Drilling techniques require a closed loop system.
Next Generation Reservoir Simulation Using Russian Linear Solvers
Authors: Beckner B. L. , Usadi A. K , Ray M. B. , Diyankov O. V. 
Published: December 2007

Abstract
During the late 1990's, Exxon and Mobil had each independently developed next-generation reservoir simulation systems. Both next-generation systems embodied a substantial number of step-out simulation technologies, which were extremely complementary. ExxonMobil moved aggressively to combine the best of both companies' technologies into one industry-leading simulation system called EMpower™. This new simulation system is currently being used to actively manage ExxonMobil's global resource base. Key features of this industry-leading simulator are described in this paper.
The new simulator employs unstructured grids to more accurately model complex geologic features, near-wellbore flow, and aquifer support. The computations are performed within the unstructured grid fabric. Interactive simulation ties together the geologic and reservoir simulation models with production data yielding high-confidence forecasts of future performance.
The linear systems that are created by an unstructured grid cannot be efficiently solved by conventional solution methods normally applied to simulators using rectilinear gridding. As a result, ExxonMobil looked to collaborate on research and development activities in the area of linear solvers for unstructured grids area and found capable research and development peers in Russia. The technical capabilities of the Russian scientific community were a natural fit to help develop a new library of linear solution methods geared towards the matrices created by the EMpower unstructured simulator. This collaborative effort yielded an unstructured linear solution library called SparSol and is the result of over 20 work years of effort at four Russian research organizations and contains numerous methods for efficiently solving the unstructured matrices produced by the EMpower unstructured reservoir simulator.
Reservoir Engineering Production Optimization System for Effective Field Management and Perfomance
Authors: Gladkov A. V. , Zakirova G. F. 
Published: December 2007

Abstract
Effective management of field development is based on daily routine engineering calculations and monitoring key performance indicators of production. At the same time it is recognized through the industry that there exists a gap between reservoir engineering and decision making process for real time reservoir management.
Whatever software one uses it will not be very useful if an engineer cannot get right input data in the proper format in time and manager is constrained in getting information for quick decision making.
Reservoir Engineering Production Optimization System is engineering information portal, which provides wide web based environment for production engineers and management of oil companies.
The system gives field data access such as well logs, core data, logs interpretation and perforation data, interactive cross sections, geological maps, PVT fluids properties, daily and monthly production, well stock information and well events.
Revolution approach is that portal provides an ability to perform standard engineering calculation from any place in corporate network. PVT correlation, well bottom-hole pressure and productivity calculations are few of them. It allows using only web browser to build log curves and well's IPR curves, to estimate artificial lift efficiency. It gives the opportunity to download data in standard software format and reduce data gathering time.
Portal presents basic collaboration environment features. News, forums, links, documents storage and engineering utilities build distributed collaborative environment and provide effective tools for knowledge management and dissemination company wide.
We believe that portal can add more value to the assets being properly tailored to specific needs of organization. This system is developed to enable robust and timely decision making for oil companies and is successfully implemented in one of them in Russia.
Seismic and Well Log Reprocessing, Re-interpretation and Geostatistical Inversion Yields More Detailed View of Yuzhno Khilchuyu Field
Authors: Fossum Bret , Snow John , Guilloux Yoann , Jason Fugro , Khromova Inga , Chernitskiy Andrey , Glebov Aleksey 
Published: December 2007

Abstract
LUKoil and ConocoPhillips formed the joint venture company NaryanMarNefteGaz (NMNG) to develop jointly owned licenses in the Timan-Pechora Basin. The Yuzhno Khilchuyu license lies in this province and, is expected to be one of the largest and most prolific fields in the region. Development of the Yuzhno Khilchuyu Field requires a huge initial investment in infrastructure, drilling and transportation. Successfully achieving acceptable reserves and production levels from the field will be critical to offset these investments. To meet this challenge a more detailed understanding of the reservoir is needed to optimize well placement.
In 2004, a large multi-disciplinary subsurface project team was formed with members from LUKoil, ConocoPhillips and Fugro-Jason to develop updated high-resolution geologic and reservoir simulation models. The seismic and well log data were completely reprocessed, resulting in a significant improvement in the overall data quality. All log, core, and production test data were incorporated into a new, fully integrated, interpretation. A sophisticated Markov Chain Monte Carlo (MCMC) geostatistical inversion methodology was applied, and the resulting high-resolution geologic model yields a dramatic increase in reservoir detail. The new model enabled the team to define the aerial extent of different reservoirs and the distribution of internal barriers. It also provided insight into porosity and permeability distribution within each reservoir, enabling better decisions on the location of production and water injection wells. Development drilling is in progress.