bluuebunny/crossref_metadata_2025_split huggingface dataset:
Choked Flow in HVO Recovery: Injection and Production in Horizontal Wells
Authors: Burtsev A. , Kuvshinov B. , de Rouffignac E. , Mollinger A. M. 
Published: December 2007

Abstract
The problem of multiphase flows in chokes presents an interesting problem for steam injection and hydrocarbon production. In both cases it is important to evaluate the maximum possible mass fluxes through a perforation. Several models are used in the oil industry for this purpose, e.g., Ashford (1974) [1], Sachdeva et al. (1984) [2], and Perkins (1993) [3]. This paper explains physical principles behind these theories, and outlines their range of applicability. The task of the study is to choose a model that would provide the most general and accurate description of a multiphase flow that can be used for implementation in a reservoir simulator. It is concluded, that existing models are very restricted. They are applicable to particular cases, where the phase transition between the liquid and gas phases is absent. A rigorous description of a multiphase flow with a phase transition does not seem feasible. The possibility of a phase transition introduces a large uncertainty in the flow parameters. This uncertainty essentially exceeds differences between predictions of existing approaches. For this reason, it is sufficiently to analyze flows within the framework of the simplest theory. Such a theory is presented in this report. We derive simple relations to estimate critical flow parameters and transported fluxes. These relations provide a relatively simple evaluation of steam injection and hydrocarbon production without significant loss of accuracy. Preliminary simulation results to illustrate the flow of a wet steam (i.e., two-phase fluid) through the choke are also discussed.
Intelligent-Well Technology Reduced Water Production in a Multilateral Oil Producer
Authors: Ajayi A. , Konopczynski M. R. 
Published: December 2007

Abstract
Excessive water production is often associated with mature fields. The source could be from the aquifer providing reservoir energy or waterflood process used for sweep enhancement. The adverse effect on oil production and reserves requires that a remedial action should be implemented to minimize the overall impact. An effective remedial action requires the identification the source of the problem.
This paper discusses the use of intelligent well completion (IWC) technology to control the amount of water production from a multi-lateral well in a mature asset in order to maximize overall oil production. The multilateral wells were drilled to connect the identified sweet spots and boost oil recovery. The field water cut ranges from 20% to 100% with an average of about 75%. The main challenge facing the asset is improving waterflood efficiency and reducing percent water cut of produced fluids. As a solution, the operator installed a Digital Hydraulic IWC system that allows for isolation of each lateral branch in the producers. This system enables an independent control of the contribution of each lateral for production optimization. This same isolation technology can be applied to water injection wells to improve the waterflooding efficiency. The system consists of remotely operated control valves and downhole packers that isolate water producing areas of the well. An ESP installation is integrated with the provision of a hydraulic disconnect, allowing the replacement of the ESP without affecting the lower completion. The disconnect tool provides re-establishment of hydraulic control line continuity upon ESP replacement.
Production tests carried out after initial installation indicate a significant reduction in water-cut from 99% to 71% resulting in significant increase in oil production. Additional oil ultimate recovery is estimated to be about 0.6x106 STB. This case study demonstrates the ability of the intelligent well system to identify and control the production of unwanted water without intervention, accelerate production, increase ultimate recovery and lower operating cost.
Stochastic Simulation of Marine Reservoirs Through Paleotopography Modeling
Authors: Kedzierski P. , Mallet J. -L. 
Published: December 2007

Abstract
Predicting lithological properties based on accurate and realistic facies models and estimating their heterogeneity are important issues for better reservoir exploitation. While the last trend in reservoir simulations consists in integrating more geological concepts in numerical methods, the proposed approach uses an innovative method binding facies occurrence to landscape attributes, such as water depth, slope angle, or distance to the shoreline. The modeling strategy is first to estimate the variations of the landscape morphology and topography throughout time to then deduce facies probability fields. The assessment of landscape variations is done in the geochronological domain, where the vertical axis is the geological time and the horizontal axes correspond to the paleogeographic coordinate system. This geochronological space is similar to the depositional space before faulting and folding. Stochastic simulations are then applied using the deduced facies probabilities. The suggested approach was applied on a realistic case study to build several realizations of facies models. They are then used as input for stochastic simulations of lithological properties of this reservoir.
Facies Analysis and Architectural Elements Within a Fluvio-Estuarine Sedimentary System: The Lower Cretaceous Bituminous Sandstones of the MacMurray Formation, Alberta (Canada)
Authors: Bailleul J. , Delhaye-Prat V. , Parize O. 
Published: December 2007

Abstract
In north-eastern Alberta (Canada), the fluvio-estuarine McMurray Formation constitutes the main bitumen accumulation of the Athabasca Heavy Oil Province. Deposited within the fluvial-to-marine transition zone, the McMurray clastic succession is characterized by the lateral and vertical juxtaposition of a wide variety of depositional processes. This led to complex lithofacies variations responsible for uncertainties in predicting reservoir heterogeneities.
In this context, a realistic paleogeographic reconstitution is necessary to localize sandy reservoirs and optimize the exploitation of bituminous sandstones. The sedimentological study of the McMurray reservoir, based on outcrops and subsurface data (cores, well logs, seismic profiles), has been undertaken along a 150 km north (distal) -south (proximal) transect.
Facies analysis permits to constrain depositional environments within the McMurray Formation. We document in detail facies associations corresponding to continental (fluvial/palustral/paleosols facies), estuarine (interaction between tide and fluvial processes) and marine environments (wave-tide to wave dominated processes). A particular attention has been paid to the nature, size, geometry and bounding surfaces of architectural elements (i.e. fluvial or estuarine channels, IHS/point-bars, tidal bars, incised valley, emerged surfaces). Stratigraphic correlations, combined with cartographic analysis, allow to evaluate how these sedimentary bodies are related in time and space. The McMurray Formation has been previously sub-divided into three units: the fluvial dominated lower McMurray, the fluvio-estuarine middle McMurray and the marine dominated upper McMurray. We notably demonstrate, on the base of size and amplitude of IHS, that the middle McMurray may be sub-divided into stratigraphic sub-units.
We also point out the significance of oxidized surfaces overlain by abrupt grain size changes. Such surfaces are important clue for sequential analysis and may have a regional extent. They should be taken into account as a potential accurate correlative tool for the McMurray Formation.
New Drilling-Fluid Solution for Unconventional Sand Wells in the San Juan Area
Authors: West G. , Morales L. 
Published: December 2007

Abstract
During the last several years, drilling deviated wells through highly bentonitic shallow formations and unconventional coal bed gas sands in the San Juan area of the Rocky Mountains has indicated the need for fluids as inhibitive as a 7% KCl/polymer system. Operators have experienced advantages with this type of system in terms of wellbore stability, penetration rates, wellbore workability and well productivity. However, increasing environmental restraints in the area make the economics of this system less desirable in terms of haul-off and disposal costs. Core samples of reactive shales in the area were analyzed to determine if a freshwater-based system could be formulated to achieve similar performance to what was previously achieved with the 7% KCl system. Several different freshwater-based muds were tested in the lab, including some high performance water-based fluids. This paper describes criteria that enables a fluid to be called a high performance fluid and reviews the data that yielded a "fit-for-purpose" high performance fluid designed for the specific clay mineralogy of the San Juan area. A field trial was initiated to decide if the lab results could be verified by actual drilling data. Performance data from the trial wells are reviewed and compared directly against the previous successful system. The paper illustrates how a fit-for-purpose high performance water-base mud can help the economics of unconventional gas sand drilling.
Keynote: Megaproject Execution
Authors: Palmer J. , Mukherjee T. 
Published: December 2007

Abstract
In a global project environment where many large projects struggle to meet their cost and schedule targets, Saudi Aramco has been executing its world-class mega projects with ever shorter schedules, and well within budget. Of the five mega projects executed in the last ten years, two were selected as Project Management Institute project of the year, and one was honored at the 2005 International Petroleum Technology Conference.
Saudi Aramco is currently executing a series of new mega projects that will help meet the world-wide energy demand increases and ensure its leadership position for years to come. Huge new gas processing plants, facilities for recovering valuable petrochemical feedstock, and new crude oil production facilities are all a part of Saudi Aramco's ambitious domestic capital program to increase oil supplies and support Saudi Arabia's burgeoning petrochemical industry.
Collectively, the Hawiyah, Khursaniyah, Khurais, Shaybah and Manifa programs will increase revenue to the Kingdom, and promote the local economy by increasing oil production by 2.85 million BPD, sales gas by 1.4 BCFD, ethane production by .45 BCFD, and condensate by 325,000 BPD. All of these projects are being executed on demanding schedules and within budget without a significant increase in Company personnel while expanding the Saudi Arabian procurement and construction content of the projects. This paper will illustrate how this is being achieved.
The paper will also show how Saudi Aramco's Project Management personnel cooperate with our internal stakeholders and contractors to deliver these projects. Integrated teams resolve technical issues swiftly, optimize scope, streamline design reviews and achieve full control of the quality and schedule.
The report will further demonstrate how the use of best practices promotes excellent project results. Our commonly used best practices include Value Engineering, Constructability, Planning for Startup, Benchmarking, Scope Definition & Control and formal use of Lessons Learned.
Saudi Aramco is dedicated to supporting Saudi Arabia's role as the leading provider of energy to the world. History has demonstrated its success. Saudi Aramco will continue to build on the success through innovation, solid integration and a strong will to meet future challenges.
Flow Reversal and Mixing
Authors: Jha R. K. , John A. K. , Bryant S. L. , Lake L. W. 
Published: December 2007

Abstract
Flow reversal provides insights about mixing mechanisms in flow through porous media. We have simulated the effect of flow reversal on mixing in two-dimensional porous media in two different ways. First, we simulate the transport of a tracer slug by solving the Navier-Stokes and convection-diffusion equations in the pore space. This approach allows investigation of solute transport and mixing in simple flow geometries from first principles without assumptions about macroscopic models for mixing. The direction of flow is reversed before solute exits the medium. The simulation studies are carried out for several diffusion coefficients, penetration depths and for several flow geometries. The second approach uses particle tracking to simulate the effect of flow reversal at larger length scales. This approach is free of numerical dispersion, can be used in the absence of diffusion and has no limits on the size of the simulation. It is, however, limited to layered media flow.
The simulation studies presented in this paper explain the mechanism of mixing and the origin of the irreversibility of mixing. We also explain several experimental observations on flow reversal tests found in the literature. Changes in pore morphology significantly enhance mixing in pore space by inducing local velocity gradients and increasing the surface area available for diffusion. This local mixing, caused by diffusion, is irreversible. However, velocity gradient (convective spreading) alone does not cause mixing. In the limit of zero diffusion, on flow reversal, mixing is completely reversible. We show that even a small amount of diffusion is enough to cause irreversibility of mixing. Although seemingly small, diffusion can homogenize concentrations in the transverse direction to flow even at the field scale. Thus it is important to include the effect of diffusion when analyzing miscible displacements in porous media.
Real-Time Fiber-Optic Distributed Temperature Sensing (DTS)—New Applications in the Oil Field
Authors: Nath D. K. , Finley D. B. , Kaura J. D. , Krismartopo B. , Yudhiarto W. 
Published: December 2007

AbstractReservoir performance monitoring can provide real-time information that can enable more timely operational decisions to be made. Often, the data can be collected without performing an intervention. This paper will discuss one of the newest reservoir monitoring techniques — fiber-optic distributed temperature sensing or DTS and some of the recent successes provided by DTS that are enabling it to be considered as an integral service for reservoir monitoring.DTS can provide a temperature profile of the entire wellbore in real time, which in turn, can provide an enhanced understanding of the downhole flow (or injection) profile. Historically, DTS has been a niche service for steamflood and geothermal applications due to its high bottomhole temperature (BHT) survivability. Acceptance of the technology, deployments costs, and value added are the reasons applications outside of steamflood and geothermal wells are being recognized.This paper presents three cases of non-steamflood applications of DTS. All three cases are from an oilfield in north-central Sumatra, Indonesia. Each illustrates how the use of DTS optimized the completion and/or improved the well/reservoir management strategies. The three cases provided the following services: Determined fluid level for electrical submersible pump (ESP) optimization.Monitored realtime fracture-height growth during a mini-frac treatment.Flow profiled in an artificial lift completion where the producing interval was inaccessible for a conventional production logging test (PLT).
Quality Assurance of the Evaluation of Hydrocarbon Saturation From Resistivity Data
Authors: Worthington P. F. 
Published: December 2007

Abstract
Validated electrical type curves, which collectively describe a continuum of conductivity behavior of fluid-saturated rocks, allow the petrophysical evaluation of hydrocarbon saturation to be set within a generic reference framework. Through the type curves, a reservoir rock can be classified in terms of its electrical character, specifically adherence to, or departures from, classical clean-sand (Archie) conditions and, by corollary, the degree of any shale (non-Archie) effects. The classification guides the approach to future core-data acquisition and to well-log analysis. As part of this process, the type curves allow pre-existing data from other reservoirs to be examined as potential analogs. In these ways, the type curves are used to ensure that interpretative algorithms are appropriate to the petrophysical task in hand.
The application of the type curves using public-domain log data from key wells in seven diverse hydrocarbon reservoirs has illustrated how petrophysical interpretations away from the key intervals can be screened with minimal calibrating information. Comparisons of best estimates of hydrocarbon-filled porosity with previously reported values have indicated a potential volumetric upside in all cases, with hydrocarbon saturations being up to 30 units higher. This is attributed to the generic nature of the screening process, which takes account of the electrical character of a reservoir without any detracting influence from procedural constraints. To further reduce the risk of underestimating hydrocarbon volumes, a set of equivalence charts has been constructed using basic petrophysical properties. These charts provide a quick-look recognition of any departures from the Archie conditions and thence whether the type curves are required.
The screening process has been synthesized into pragmatic workflows, whose adoption should impart additional quality assurance to petrophysical applications.
Intelligent Well Automation—Design and Practice
Authors: Mathieson D. , Giuliani C. , Ajayi A. , Smithson M. 
Published: December 2007

Abstract
The commercial application of Intelligent Well Technology is fast approaching the ten year milestone. Expanding the range of advanced completion and monitoring products with particular focus on reliability engineering has been the main theme for this sector. As this technology has matured, research focus has shifted to Intelligent Field or Smart Field concept studying the potential of wide-scale automation and optimization.
This paper describes the development of Intelligent Well surface control systems, aimed particularly at providing automation and optimization of well based processes as a means to achieve advanced well management. A simple layer model is proposed describing an increasing level of control and automation.
Data standards and connectivity are discussed as the vehicle to achieve wide-scale integration of advanced well management, as this capability is portrayed as one of the stepping stones of Intelligent Fields.
Apparatus for Measuring the Dynamic Solids-Settling Rates in Drilling Fluids
Authors: Murphy R. , Jamison D. , Hemphill T. , Bell S. , Albrecht C. 
Published: December 2007

Abstract
Barite Sag is a reoccurring problem with many oil-based drilling fluids. Attempts to correlate sag tendencies to various rheological properties commonly used to benchmark drilling fluids have had limited success in prevention and anticipation of sag problems in the field. Herein is presented a new testing apparatus for dynamic and static settling rate (sag) measurements, which has been proven to provide a better understanding of the sag phenomena as well as provide a better means to characterize fluid performance. This apparatus greatly expands the precision of sag measurements over previous techniques and allows testing conditions similar to those experienced downhole. Good correlation has been found between settling rate measurements and performance of drilling fluids in the field.
Systematic Approach to the Design and Application of a Well-Fracturing Fluid To Ensure Deepwater Production
Authors: Park E. , Olson K. E. , Weber B. J. , Cawiezel K. E. , Monroe T. D. , DeVine C. S. , Cutler J. L. , Berry S. L. 
Published: December 2007

Abstract
As deepwater exploration projects in the Gulf of Mexico and other offshore areas have gained momentum, development activities in all areas of drilling, completion and production of these wells have faced significant challenges. One key area of concern in completion of these wells is the design, application and compatibility of the fracturing fluid to ensure optimum well performance. Deepwater engineering design and application of fracturing fluids are presented with some unique challenges in well depths that can exceed 20,000 ft with pore pressures greater than 20,000 psi. One major issue facing deepwater fracturing is generating enough bottomhole treating pressure to create a hydraulic fracture at the sandface without exceeding the limitations of the hydraulic equipment at the surface. In order to overcome these surface hydraulic equipment limitations and still create the needed hydraulic fracturing pressure at the sandface, weighted fracturing fluid formulations have been developed to address these issues. Furthermore, due to the increased travel distance to the sandface and the extreme temperature ranges that the fluid is exposed from the mudline to the BHT, the fracturing fluid must have flexibility to be designed to meet specific density, extended crosslink delay times, friction pressures, and compatibility specifications.
This paper summarizes a study to formulate a sodium bromide weighted, delayed crosslink fracturing fluid system to meet the fluid and engineering guidelines for the fracturing application. After baseline fluid formulation studies with the weighted sodium bromide, delayed crosslink fracturing fluid system were designed, rheological performance with breakers at BHT were run, stacked cell regained conductivity lab measurements were performed and friction pressures were determined. Additional studies were also conducted with this weighted fracturing fluid to determine compatibility with the well's produced crude oil and returned permeability studies utilizing formation cores.
DTS Transient Analysis: A New Tool To Assess Well-Flow Dynamics
Authors: Johnson D. , Sierra J. , Gualtieri D. , Kaura J. 
Published: December 2007

Abstract
Distributed temperature sensing (DTS) is a valuable tool used to understand the dynamics of oil and gas production and injection rates. This is achieved by monitoring the temperature variations caused by flow or injection rates at the reservoir entry points. Although most documentation to date has been limited to the discussions resulting from the examination of steady-state temperature profile behavior, significantly more knowledge and better assessment of "what's happening" in wells can be gained when sequences of complete wellbore temperature profiles are analyzed during rate-related or other induced thermal transient events, such as seen in pressure transient analysis.
DTS technology allows complete wellbore temperature profiles to be obtained in a short period of time without the need for wire line. Discrete temperature measurement information can be obtained along the entire wellbore using optical fiber and a laser source/detector to repeatedly pulse light down the fiber and detect the back-scattered light from every depth. The back-scattered light is the result of the interaction of each laser pulse with the fiber molecules and is proportional to the temperature of the glass at a given depth. Intensity responses of repeated light pulses are averaged to obtain acceptable temperature resolution and can be improved by increasing acquisition time.
This paper discusses the value added from transient temperature analysis of DTS profiles for oil and gas wells under production, injection, and treatment conditions. Data taken with DTS technology and thermal simulators from several actual field cases will be provided to demonstrate how these techniques can improve analytical capabilities and how a temperature change has a direct relationship to production/injection layer contributions, reservoir flow properties, tubular leaks, and steam breakthrough locations. The field cases also will demonstrate how a DTS-acquired transient temperature profile analysis can be applied. In addition to the improved data acquisition capabilities, the paper will also provide the cost and safety advantages gained by using DTS transient analysis techniques.