bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Critical Review of Hybrid Steam-Solvent Processes to Recover Heavy Oil
Authors: Ardali M. , Barrufet M. A. , Mamora D. D. , Qiu F. 
Published: October 2012

Abstract
Steam-Assisted Gravity Drainage (SAGD) is the main commercial technology used for in-situ recovery of Canadian heavy oil and Bitumen. It is commercially proven and delivers high oil rates and high ultimate recoveries. One of the long-term concerns with the SAGD process is high energy intensity and related environmental impacts.
Hybrid processes have been developed to take partial advantage of steam and solvent processes while introducing a more efficient and more economically viable recovery methods. Several processes such as Propane-SAGD, Expanding Solvent-SAGD (ES-SAGD), Solvent-Aided Process (SAP), Liquid Addition to Steam to Enhance Recovery (LASER) and Steam-Alternating-Solvent (SAS) were proposed; some of them currently under pilot test. Hybrid steam-solvent processes aim to accelerate oil production rate with lower cost than SAGD and also increase the ultimate oil recovery.
Despite remarkable amount of laboratory and computational studies on these processes, there was no extensive critical review of the knowledge obtained for more than a decade. The current level of understanding of the hybrid processes and knowledge around the fundamental physics and mechanisms involved are not fully satisfactory. We believe that a critical review of the status of the hybrid processes will fill the gap by shedding the light on the deficiencies and the limitations of the process, further development areas, and new research topics. Analytical, numerical simulations, laboratory modeling efforts along with pilot test results are summarized. In addition, the main technical challenges of different aspects of hybrid steam-solvent processes are analyzed at different levels. In this paper, special attention is given to a) The effect of reservoir and operational parameters, b) solvent injection strategies, c) The inconsistency between laboratory, simulation and field results and d) problems faced in numerical modeling (capturing the physics of heat and mass transfer).
It is believed that a good compilation of the records produced over one decade will constitute a useful reference for the industry and academics. Analytical, simulation, laboratory studies and reported field data strongly support hybrid steam-solvent processes. However, the results are mixed at different level levels and there exists some inconsistencies. The cost of the solvent retained in the reservoir is the major concern and the economics of selected hybrid steam-solvent process for a specific reservoir has to be verified using available tools. The main challenges are verifying effective mixing of the solvent with the in-situ bitumen, managing the solvent placement and distribution in the reservoir, reliably determining the incremental benefit of solvent-addition and ensuring economic solvent recovery.
Effect of Capillary Pressure on Fluid Density and Phase Behavior in Tight Rocks and Shales
Authors: Nojabaei B. , Johns R. T. , Chu L. 
Published: October 2012

Abstract
Phase behavior is important in the calculation of hydrocarbons-in-place and in the flow of phases through the rocks. Pore sizes can be on the order of nanometers for shale and tight rock formations. Such small pores can affect the phase behavior of in situ oil and gas owing to increased capillary pressure. Not accounting for increased capillary pressure in small pores can lead to inaccurate estimates of ultimate recovery, and saturation pressures. In this paper, capillary pressure is coupled with phase equilibrium equations and the resulting system of nonlinear fugacity equations is solved to present a comprehensive examination of the effect of small pores on saturation pressures and fluid densities. Binary mixtures of methane with heavier hydrocarbons, and a real reservoir fluid from the Bakken shale are considered.
The results show that understanding the impact of small pore throats on PVT properties explains the inconsistent GOR behavior, high flowing bottomhole pressures, and low gas flow rate observed in the tight Bakken formation. The small pores decrease bubble-point pressures and either decrease or increase dew-point pressures depending on which part of the two-phase envelope is examined. For the pore radius of 10 nanometers in the Bakken shale, the calculations show that there is more than a 900 psi reduction in the bubble-point pressure as the reservoir is depleted. Further, reduction of oil density due to small pores can impact the formation oil factor and ultimate reserve calculations. The results also show that the change in saturation pressures and fluid densities are very dependent on the values of the interfacial tension used in the calculations.
Laboratory Testing and Numerical Modelling of Fracture Propagation from Deviated Wells in Poorly Consolidated Formations
Authors: Ispas Ion , Eve Robin A. , Hickman Randall J. , Keck Richard G. , Willson Stephen M. , Olson Karen E. 
Published: October 2012

Abstract
This paper presents the results of an integrated laboratory and numerical modelling study on the effect of wellbore deviation and wellbore azimuth on fracture propagation in poorly consolidated sandstone formations. The goal of this project was to develop an understanding of how fractures would transition from single planar fractures to non-planar transverse fractures for fields in the deep-water Gulf of Mexico.
The foundation of this work was over 40 fracturing laboratory tests to measure fracture propagation geometries for a range of well deviations, differential horizontal stresses and rock strength. The samples tested were from three outcrops with unconfined compressive strength (UCS) values ranging from 300 – 1000 psi. For boreholes having low deviation angles and small differential stresses a vertical single planar fracture was created, aligned with the wellbore, as expected. As the well trajectory and stress contrast increased the fractures became more complex, with transverse turning fractures no-longer aligned with the wellbore.
These laboratory results were used to develop and calibrate a new fully-3D finite element model that predicts non-planar fracture growth. The model matches the details of the laboratory tests, including the transition from planar vertical to nonplanar transverse fractures as the well deviation, azimuth and stress differentials increase. After initial model development and calibration was complete a model of a complex case was run before showing any experimental results to the modellers. The model successfully predicted the transverse non-planar results found in the laboratory; this gave us increased confidence in the model as a predictive tool.
This work has now been applied with excellent success to four deepwater fields. We have recommended changes in maximum well deviations, performed post-job analyses on wells that had high deviations, and have increased our understanding of the impact of layered formations on fracture growth in these fields.
A New Method for Earlier and More Accurate EUR Prediction of Haynesville Shale Gas Wells
Authors: Xie Xueying , Fairbanks Michael D. , Fox Kevin S. , Koinis Rena L. 
Published: October 2012

Abstract
Haynesville shale gas wells are operated over a wide range of back pressures, varying from 8000 psi or higher at early time to 1000 psi or lower at late time. Traditional Arps Decline Curve Analysis (DCA) presumes constant back pressure, and therefore over-predicts Estimated Ultimate Recovery (EUR) for Haynesville wells when applied at early time, prior to reaching line pressure. A new method has been developed to forecast well EUR earlier and more accurately by using pressure normalized rate instead of actual rate. In this method, the actual rate is normalized to the rate corresponding to a constant operating pressure. DCA methodology may then be applied to this normalized rate to forecast EUR. This new method yields consistent EUR predictions from much earlier time than traditional DCA methods, and converges to the same EUR as the traditional DCA method once constant flowing pressure is reached. Both field data and simulation results confirm the advantages of this method. The new method is practical to use and it reduces the uncertainty range of well performance predictions, thus providing better and earlier well performance comparisons, a quicker assessment of completion trial results, and more accurate booking of reserves and resources.
New Insights into Steam-Solvent Co-injection Process Mechanism
Authors: Jha Raman K. , Kumar Mridul , Benson Ian , Hanzlik Edward 
Published: October 2012

Abstract
We present results of a detailed investigation of the steam-solvent co-injection process mechanism using a homogeneous numerical model and three different solvents. The mechanistic model developed in this study describes coupled heat and mass transfer at the chamber boundary and its implications in detail. We present a composite picture of interplay of the process variables, the important phenomena occurring in the different regions of the reservoir and their consequences for oil recovery. The results are corroborated by literature experimental results and field data. The model will help with selecting the best operating strategy for a given reservoir.
Results show that the injected steam and solvent vapor condense near the steam chamber boundary. The temperature near the chamber boundary drops because of a reduction in the partial pressure of steam.The condensed steam-solvent mixture drains outside the chamber boundar leading to the formation of a mobile liquid stream where heated oil, water and condensed solvent flow together to the production well. The condensed solvent and water are immiscible and therefore, form separate flow streams. The condensed solvent mixes with the heated oil in the water-oil stream and reduces its viscosity beyond that caused by heating alone, resulting in higher oil production rate. As the steam chamber expands laterally because of continued injection and temperature in the hitherto drainage region increases, part of the condensed solvent mixed with oil evaporates. This lowers the residual oil saturation in the steam chamber. Therefore, ultimate oil recovery with steam-solvent co-injection process is higher than that in steam only injection. The higher the solvent concentration in oil at a location, the greater is the reduction in the residual oil saturation at that location.
Thus, steam-solvent co-injection causes a higher oil production rate because of an additional reduction in oil viscosity and a higher ultimate recovery because of a reduction in residual oil saturation.
Field Application of Inversion Method to Determine Acid Placement with Temperature Profiles
Authors: Tan X. , Almulla J. M. , Zhu D. , Hill A. D. 
Published: October 2012

Abstract
Optimum fluid placement is crucial for a successful acid stimulation treatment, especially in thick, highly heterogeneous carbonate formations with multiple zones and/or extensive productive intervals. A variety of diversion methods are applied in acidizing treatments to evenly place acid along the well, but the effectiveness of these diversion methods is generally only inferred from the rate and pressure behavior during the treatment, and is not known with any certainty. Recently, distributed temperature sensing technology has enabled us to observe dynamic temperature profiles along the wellbore during and immediately following an acid treatment. This technology allows us to monitor and evaluate treatments and diversion methods in real-time from captured sequence of temperature profiles at different times during and after acid injection.
We presented a mathematical model in previous papers to simulate the temperature behavior in the formation and along the wellbore, during and shortly after an acid treatment (Tan, 2009 and 2011). An inversion procedure was also included to interpret the acid distribution profile from the measured temperature data in a hypothetical example. In this paper, we apply our model to a field case. The well is a gas producers and was stimulated with acid treatments. The temperature data was measured with DTS tool during shut-in period, and shortly after each stage of the treatments. The model is used to quantify the acid distribution with the temperature data to evaluate the efficiency of acid treatments. We have focused on diagnosing the volume of acid placed in each zone with the shut-in temperature data. Results indicate that the model is applicable in the field operation for acid profiling and is helpful to evaluate and optimize acid treatments.
Coiled Tubing Drilling: Directional and Horizontal Drilling With Larger Hole Sizes
Authors: McCutchion Paul , Miszewski Toni , Heaton Joe 
Published: October 2012

Abstract
Currently the options for directional drilling of larger hole sizes, such as those greater than 6", with Coiled Tubing Drilling (CTD) are limited. This paper introduces a new system that utilizes a 5.0" BHA with a Rotating Orienter. The BHA is the first drilling tool to utilize a solid state MEMs gyro for directional measurement at all inclinations from vertical to horizontal. This paper aims to show that the use of this type of tool in combination with a Hybrid Drilling Rig can provide a technically and economically feasible alternative, which could expand the size of the CTD market.
The paper reviews a 5-well drilling program that has been carried out in order to assess the capabilities of the tool and the drilling techniques used. The 5 wells consist of directional and horizontal profiles and both mud and an air mist were used as the drilling fluid. Details of the equipment used, the performance of the tools and lessons learnt from the operations are all provided.
All initial aims of the project were met with the tools reaching the target zone on all wells. Accurate, reliable and efficient drilling was demonstrated, whilst drilling hole sizes ranging from 6.25" to 8.5".
Optimizing Completion Design in Horizontal Shale Wells by Integrating Rock Properties Derived from Multi-component Seismic Data
Authors: Brettwood Paul , Randazzo Santi , Leveille Jacques , Harris Ron , Caron John David 
Published: October 2012

Summary
Unconventional resource plays involve the development of some unusual reservoirs, such as shales or other very tight formations with very low natural permeability in the nano-darcy range. Reservoir development for these plays requires the identification of "sweet spots" for fracturing/production purposes, in what is usually a very inhomogeneous "reservoir". The nature of these sweet spots is somewhat elusive and we will choose to define the term as any portion of the reservoir that gives enhanced hydrocarbon production after optimization of the reservoir through some mechanical process such as hydraulic fracturing. The geophysical characterization of these sweet spots is highly dependent on the detailed rock properties of the shale, but most often takes the form of some highly optimized seismic attributes obtained after careful seismic processing and a seismic inversion. These seismic attributes may not be derived from p-wave data alone. In fact we will argue that the seismic attributes most often used in the identification of sweet spots in shale plays usually require a reasonably accurate determination of formation density which, in most circumstances, cannot be accurately estimated from p-wave data alone. We will then present the impact of converted waves and the additional information that they can bring to these developments when combined with other data.
The workflows and technologies discussed in this paper are generally applicable to any unconventional resource play. However to focus the discussion we will only use examples from the Marcellus shale play in the US.
Evolving a Business-Driven Competency and Employee Development Program to Deliver Superior Business Results and Satisfy Regulatory Requirements
Authors: Leuro Jorge , Kruger Todd 
Published: October 2012

Abstract
Through sustaining the competency and employee development program, an oilfield services company has documented exciting evidence that demonstrates a direct link between the competence of the workforce and the effect on business results. This evidence is in the form of strong positive correlations between the competence of the workforce and primary key performance indicators (KPIs), which include a mixture of strategic measurements in the safety, service quality, financial results, and human resources areas.
This paper describes how the global competency and employee development program has evolved to enable its 11 product service lines (PSLs) and eight support functions in eight regions to achieve record levels of engagement in the program that supports the development needs of the existing 70,000 employees, including the 18,000 new hires from last year, to continue to have a positive effect on business results.
This evolution has introduced improvements based on best practices, in addition to upgrades to the competency model and the online competency system (software). The implementation of fundamental changes to the program has been successful throughout the PSLs and regions as a result the change management approach adopted and the commitment of management.
The improvements described in this paper and the foundation provided in the past enable this service company to be in an optimum position to meet regulatory or customer requirements related to managing the competence of the company's workforce.
Enhanced Capabilities for Formation Testing Tools with a Highly Sophisticated Pump Control System
Authors: Cartellieri Ansgar , Kischkat Tobias , Niemeyer Eick , Meister Matthias 
Published: October 2012

Abstract
Formation testing tools in wireline operations typically use hydraulic pump systems for fluid cleanup and sampling. As there is an electric connection and a communications channel suitable for interactive tool operation to the wireline systems, the operator interacts continuously with the system and can adjust the pump parameters to the downhole conditions. Due to the low bandwidth of the mud pulse systems this is not possible in the while-drilling environment. Moreover, the hydraulic concept makes a precise control of the pump parameters nearly impossible.
To overcome this challenge a highly sophisticated pump and pump control system is necessary. A closed-loop control system and different intelligent algorithms avoid pumping below the bubblepoint and thus prevent the alteration of the fluid sample.
In combination with pressure gauges the innovative pump control system delivers additional information about the downhole fluid. While pumping it is possible to calculate continuously the compressibility of the fluid and deliver a precise cleanup mobility. The pump control minimizes the backflow and mud valve switching force and it is possible to derive the effective volume pumped that corrects the difference between pump rate and flow rate.
In this paper the capabilities and operation of this innovative pump system within the new logging-while-drilling (LWD) fluid analysis and sampling tool will be shown. It will be demonstrated that it is possible to run a fluid sampling operation in a nearly automated system. The continuous interaction of the operator with the system to control the pump process will not be necessary.
The results from different field tests will be compared and the advantages of the system will be discussed. An outlook will be given how to implement this technology in further developments and how sampling tools can benefit from this technology in challenging environments like unconsolidated sands.
Discrete Wellbore and Fracture Modeling for Unconventional Wells and Unconventional Reservoirs
Authors: Hazlett Randy D. , Babu D. Krishna 
Published: October 2012

Abstract
Newly-developed, generalized analytic solutions to the heat equation for arbitrary 3D well trajectory in anisotropic media are demonstrated to solve benchmark horizontal and slanted well productivity problems with unprecedented speed and accuracy. Arbitrary well trajectory is constructed as an assemblage of spatially integrated, linear well segments, as opposed to a distribution of numerically integrated point sources, to provide advantages in both computational speed and accuracy in singularity handling. Production from each arbitrarily-oriented segment is reduced to a combination of purely analytic expressions and rapidly-convergent, exponentially-damped infinite sum approximations. With offered flexibility in cell boundary conditions, the expressions can yield stand-alone well productivity estimates for complex wells or serve as the basis for advanced well equations, if integrated within a numerical reservoir simulator. Transients are also computed with analytical integrations in time, thus requiring no time marching. The breakthrough speed and accuracy in productivity assessment opens possibilities for advanced well testing and reservoir characterization methods.
We further demonstrate the usefulness of analytic methodology with several time-dependent, discrete fracture problems for shale gas production with typical Barnett conditions, allowing direct use of complex fracture patterns, such as those interpreted from microseismic. In addition to uniform flux and uniform pressure modeling options, a new analytic model is introduced that is capable of modeling both time-dependent material transport between matrix and a stimulated zone and the interplay between a well and fracture. We illustrate our solution method with fractured Barnett well examples from the literature. With optional effects such as gas desorption and stress-dependent fracture conductivity as easy add-ons, we can produce full operational life production forecasts for shale or tight gas reservoirs from discrete, complex fracture patterns along with reservoir pressure mappings in a matter of minutes on common PC platforms.