bluuebunny/crossref_metadata_2025 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

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

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

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

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

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

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

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

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

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

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

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.
A Fully Coupled Model of Nonisothermal Multiphase Flow, Solute Transport and Reactive Chemistry in Porous Media
Authors: Zhang Ronglei , Yin Xiaolong , Wu Yu-Shu , Winterfeld Philip H.
Published: October 2012

Over the past decades, geochemical reaction has been identified through experiments in different processes, e.g. the CO2 EOR process, the CO2 sequestration, the enhanced geothermal system. Research has gradually led to the recognition that chemical reactions between injected fluid and mineral rock have significant impacts on fluid dynamics and rock properties in these processes. However, for the majority of the reactive transport simulators, the sequential calculation processes of fluid flow, solute transport, and reactive geochemistry result in numerical instability and computation efficiency problems. In this paper, we present a fully coupled computational framework to simulate reactive solute transport in porous media for mixtures having an arbitrary number of phases. The framework is designed to keep a unified computational structure for different physical processes. This fully coupled simulator focuses on: (1) the fluid flow, solute transport, and chemical reactions within a three- phase mixture, (2) physically and chemically heterogeneous porous and fractured rocks, (3) the non-isothermal effect on fluid properties and reaction processes, and (4) the kinetics of fluid-rock and gas-rock interactions. In addition, a system of partial differential equations is formed to represent the physical and chemical processes of reactive solute transport. A flexible approach of integral finite difference is employed to to obtain the residuals of the equation system. Jacobin matrix for Newton- Raphson iteration is generated by numerical calculation, which helps the future parallelization of the fully coupled simulator. Finally, the fully coupled model is validated using the TOUGHREACT simulator. Examples with practical interests will be discussed, including CO2 flooding in a reservoir, supercritical CO2 injection into a saline aquifer, and cold water injection into a natural geothermal reservoir. This type of simulation is very important for modeling of physical processes, especially for CO2 EOR and storage, and geothermal resources development.
Paraffin Deposition Analysis for Crude Oils under Turbulent Flow Conditions
Authors: Karami Mirazizi Hamidreza , Shang Wei , Sarica Cem
Published: October 2012

This paper presents the results of a modeling study for paraffin deposition under single-phase turbulent flow conditions. Analysis on flow loop deposition data is presented for various crude oils such as South Pelto crude oil, Garden Banks condensate and Trans Alaska Pipeline System (TAPS) crude oil. A new closure relationship simulating shear effects is proposed.

The experimental data were obtained under single-phase turbulent flow conditions using different types of crude oils on different test facilities at TUPDP (Tulsa University Paraffin Deposition Projects). These data were used to develop a correlation which can be used to predict the relative difference between the estimated wax mass deposition rate and mass diffusion rate from Fick's law as a function of the Nusselt and Sherwood numbers representing the heat and mass transfer characteristics under turbulent flow conditions. Uncertainty analysis was conducted on this correlation and most of the data points fall within the range of ±25%. Model predictions have been compared using a film mass transfer model and equilibrium model. It is observed that the film mass transfer model always over predicts the deposition rate. But the equilibrium model can both under predicts and over predicts the deposition rate. The results presented in this paper can be used to improve the accuracy of paraffin deposition model predictions under turbulent flow conditions.
Gas/Water IFT Measurements Using the Pendant Drop Method at HP/HT Conditions: The Selected Plane vs. Computerized Image Processing Methods
Authors: Shariat A. , Moore R. G. , Mehta S. A. , Van Fraassen K. C. , Rushing J. A.
Published: October 2012

This paper presents a comparative evaluation of gas-water interfacial tensions (IFT) measured using the pendant drop technique and computed using either the Selected Plane (SP) or the Computerized Image Processing (CIP) Methods at high- pressure/high-temperature (HP/HT) conditions. Both the SP and CIP Methods are based on solutions to the Young-Laplace equation. The SP Method, which is derived from an approximate solution originally developed by Bashforth and Adams (1883), is dependent on just two pendant droplet dimensions. Further, the solutions were generated for the air-water system at pressures and temperatures much lower than typically encountered in oil and natural gas reservoirs. However, these solutions are often extrapolated mathematically to HP/HT conditions.

Although it is relatively simple to use, the IFT computational accuracy using the SP Method is questionable since it is dependent on the precision to which the two pendant droplet dimensions are measured. However, improvements in computerized data acquisition and imaging systems have made it possible to digitize droplet shapes completely such that IFTs may be computed using the entire shape. So while the CIP Method is also an approximate solution (numerical solution which discretizes the droplet interface) to the Young-Laplace equation, it utilizes many more points on the pendant droplet and incorporates the actual fluid properties directly into the solution. Therefore, the question addressed in this study is: what is the accuracy of the SP Method for computing gas-water IFTs at HP/HT conditions?

To answer this question, we conducted a two-stage study. First, we used the pendant drop method and measured droplet dimensions for the gas-water system at pressures of 1,000 psia to 20,000 psia and temperatures of 122°F, 212°F, 300°F, and 400°F. We then compared gas-water IFTs computed using both the SP and CIP Methods. The comparative evaluation indicates the gas-water IFTs from the SP Method are generally and consistently lower than IFTs from the CIP Method. Differences between the two methods are dependent on pressure/temperature conditions, gas composition, droplet geometry and size, and the illumination when the droplet shape is photographed. However, the maximum absolute mean error for all evaluations was less than 3.5%, suggesting the SP Method is valid for computing gas-water IFTs at HP/HT conditions.
Well Planning Based On Passive Magnetic Ranging And Magnetized Casing
Authors: Noort Roger van , Abrant William , Towle James
Published: October 2012

No one wants or expects to have to drill a relief well; however, it is a fact that a number of relief wells are required each year. Recent events have drawn attention to the need for, and the benefit of, comprehensive contingency relief well planning. On a deepwater Gulf of Mexico (GOM) well, it was noted that "Active Electro Magnetic Ranging" technology would not work at the planned intercept depth due to the presence of a large salt body. Furthermore, the planned survey program would result in a relatively large Ellipse of Uncertainty (EOU) at the desired intercept depth, which would make a relief well intercept on a first pass unlikely to succeed. A combination of "Passive Magnetic Ranging" and a modified survey program was identified as the solution to demonstrate the ability to intercept the target well on the first attempt.

Due to the inherent problems associated with "active" ranging technologies in salts (De Lange, J.I., Darling, Toby J., 1990), "passive" MWD Ranging was identified as the likely ranging technique due to the fact that it is not impacted by formation type (salt). Based upon the modified survey program, it was determined that a reliable range of detection of eighty feet (80’) would be required to qualify passive magnetic MWD Ranging technology as the primary ranging technique should a relief well be required. This detection range would allow a "no flyby" intercept (also referred to as a direct intercept) by the theoretical relief well. To confirm this capability, a qualifying demonstration protocol was established and executed using casing joints that would ultimately be run into the well. The proving tests were conducted first with only remnant magnetization of the casing joints and then again after the casing joints had been magnetized with a coil.
New Logging-While-Drilling Ranging Technique for SAGD: Theory and Experiment
Authors: Bittar Michael , Wu Hsu-Hsiang , Li Shanjun
Published: October 2012

In a heavy oil production steam-assisted gravity drainage (SAGD) project, two horizontal wells were separated by only a few meters. The separation had to be kept parallel to enable steam to be injected from one well and oil to be produced from the other twin well located below. In general, the currently practiced techniques rely on wireline technology to position the wells; in many cases, the technique requires access to the existing well in SAGD operations.

This paper presents a novel technique for locating the relative position of one well with respect to another by using a rotating azimuthal logging-while-drilling (LWD) electromagnetic tool. With this technique, the relative position between a well with a rotating LWD electromagnetic tool and casing in an adjacent existing second well can be determined in real time. Consequently, the relative position and the relative distance between the two wells provide the field engineer with calculated inter-well spacing and direction to maintain the two wells parallel and spaced within a certain distance apart.

This paper discusses and explains the fundamentals of the new LWD ranging technique. Several cases were modeled and compared with experimental data collected in a water tank with a conductive casing. The experiments successfully validated the computed responses. The casing position and distance to the LWD tool were successfully determined. This new LWD technique presents a ranging method alternative to the existing wireline technique and can be successfully used in a SAGD application.
Organizational Success Integrating Safety and Training with Operations: An Engineered Approach
Authors: McNeil Michael , Howard Myke
Published: October 2012

Success for any company in today's highly competitive global market is dependent on ensuring company-wide safety and efficiency are always at peak performance.

At the core of this success is the philosophy that Safety and Training are not about attaining compliance; but rather, about engineering a cultural improvement that holds an organization's primary assets—its employees—as a top priority. To achieve this end, Safety and Training must overcome the traditional roadblocks such as time, cost and attitude. By expanding the emotional and intellectual capacity of the organization's employees through a consistent demonstration of value, Safety and Training become integral to the culture and lifestyle of an organization.

This paper will demonstrate statistically how successful integration of Safety and Training improves the overall culture and performance of an organization and how such an investment can lead to greater efficiency and ultimately greater profitability.

It illustrates how, through the acceptance of improved integration and awareness processes, one organization experienced 380% growth over a three-year period with a 329% reduction in Total Recordable Injury Frequency (TRIF). Additionally, the organization's employee retention rate improved 31% resulting in a more experienced workforce, improved efficiency, increased service quality and stronger customer relationships.

The main objective of Safety and Training is to satisfy the needs of the end-users—employees—while propelling the organization forward. The reciprocal relationship between Safety, Training and Operations stimulates personnel to challenge Safety and Training to provide continued improvement. The upshot of this is greater profits stemming from a more motivated and efficient workforce, which sustains fewer injuries, related downtime and cost.
An Approach to Model CHOPS (Cold Heavy Oil Production with Sand) and Post-CHOPS Applications
Authors: Rangriz Shokri A. , Babadagli T.
Published: October 2012

Due to its lower cost, the cold heavy oil production with sands (CHOPS) method is becoming more popular, not only in Canada where it originated, but also in many other countries including Venezuela, Kuwait, Russia and China. However, this method has several practical limitations. It continuously changes the geo-mechanical and petro-physical properties of the reservoir due to the sand produced, resulting in high permeability channels known as wormholes. Moreover, the method has a low oil recovery factor of 5 to 15 % and this entails further recovery techniques.

Thermal methods after CHOPS are not usually favorable due to heterogeneity and reservoir instability. In addition, the CHOPS method is typically applied in thin formations in which heating by injected steam is characteristically inefficient. Solvent injection possesses similar problems caused by heterogeneity and cost. An option could be the hybrid application of steam/solvent. Assessment of this technique first requires a realistic modeling of the CHOPS application. Due to dynamic changes in reservoir properties, no valid model is yet available to accurately simulate CHOPS production.

Our main focus in this paper is to investigate efficient EOR/IOR methods after CHOPS. To achieve this, we first propose a partial-dual porosity approach coupled with algorithms for wormhole generation to create a realistic static reservoir model. After generating fractal wormhole patterns of different kinds using a diffusion limited aggregation (DLA) algorithm, they were introduced into a reservoir model with extremely fine grids. It is assumed that wormhole's properties are a function of its radius and can be controlled along its length and pattern, which facilitates the history matching process. After validation of the model using data obtained from a field in Alberta, several post-CHOPS scenarios including thermal, solvent and thermal/solvent hybrid applications were simulated.

The new modeling workflow, proposed and validated to model the CHOPS process with realistic wormholes representations along with a simple mathematical wormhole network growth model, are the primary contributions of this paper. Secondarily, hybrid steam/solvent applications were evaluated using this validated static model and compared with the sole application of steam and solvent.
Reservoir Parameter Estimation with Improved Particle Swarm Optimization
Authors: Awotunde Abeeb A.
Published: October 2012

Effective reservoir management relies heavily on the accurate prediction of reservoir flow performance over the entire life of the reservoir. Accurate prediction of flow performance is possible only if reservoir flow parameters are known with reasonable accuracy. Consequently, a major challenge in reservoir management is the estimation of reservoir parameters that affect the flow and distribution of reservoir fluids the most.

Estimation of distributed reservoir parameters has been done using mainly gradient-based optimization algorithms because these algorithms are relatively faster than global (stochastic) optimization algorithms. However, the gradient-based algorithms are local in nature and thus limited in their search ability. In this paper, we present a local-global optimization method that generates multiple realizations of reservoir parameters at coarse scale. The method involves the use of a local search optimization algorithm to parameterize the model space at a coarse scale followed by a stochastic search for better estimates in the vicinity of the local estimate. At the end of the search, the method produces a distribution of estimates that can be used for uncertainty quantification. To test the effectiveness of the method, the local-global optimization algorithm was applied to a sample reservoir with a known distributed permeability field. Results obtained indicate that the method is able to produce multiple history-matched realizations of the permeability field, some of which are closer to the true reservoir permeability distribution than the estimate obtained from an exhaustive local search.
First Highly Deviated Openhole Gravel Pack Jobs in the Mediterranean with Alternate Path Technology
Authors: Bessada Ashraf M. , El-Shafaie Ibrahim , Nashaat Mohamed , Roy Alistair , Russell Wood W. , El-Attar Hesham Bahaa
Published: October 2012

Sand control, particularly gravel packing, is a common practice in the Mediterranean Sea due to the presence of poorly consolidated sandstone reservoirs. Open Hole Gravel Packs (OHGP) in highly deviated wells present an additional challenge due to the risk of sand bridging during the alpha wave propagation. The risk of bridging is escalated further in low fracture gradient environments where the pumping rate is reduced to avoid inducing losses. A major operator in Egypt has performed the first highly deviated OHGP jobs in the Mediterranean using Alternate Path screens. A series of qualification work was performed by the service provider during the planning phase for the 2 wells. Planning work included fluid rheology tests, flow loop testing, modeling full scale tests to achieve desired accuracy with gravel transport equations, pretreatment numerical simulations and post-treatment comparison of simulated data to actual data. Moreover, a lightweight proppant (LWP) product was qualified and successfully pumped on the second well where the fracture gradient was particularly low due to reservoir depletion. This paper discusses the planning, execution and post-job review work that was performed for these wells to produce two successful sand control jobs. Recommendations and lessons learnt for the future wells are also included.

With the Industry and specifically the Mediterranean Basin moving towards more challenging wells requiring sand control in ever higher deviations and significantly depleted sands these highly deviated gravel packs with high overbalances are becoming increasingly important to unlock resources and maintain field plateau.

The paper will detail the simulated results based on flow loop testing and how they compare with the actual job data. Successful sand control integrity was achieved with amount of gravel pumped exceeding 100% of the theoretical volume and sand free production achieved on both wells. Individual well performance with estimated skin values will also be shared.
Fluid Characterization Using an EOS for Compositional Simulation of Enhanced Heavy-Oil Recovery
Authors: Kumar Ashutosh , Okuno Ryosuke
Published: October 2012

Reliable design of solvent injection for enhanced heavy-oil recovery requires accurate representation of multiphase behavior for heavy-oil/solvent mixtures in a wide range of pressure-temperature-composition conditions. Characterization of a heavy oil is more difficult than that of a conventional oil because the former is conducted under more uncertainties in composition and PVT data. Volume-shift parameters are often required to improve density predictions, separately from compositional behavior predictions, in conventional fluid characterization methods (CM). Thermodynamically, however, volumetric behavior predictions (e.g., densities) are consequences of compositional behavior predictions.

In this paper, we develop a new fluid characterization method (NM) that gives accurate multiphase behavior representation for heavy-oil/solvent mixtures without using volume-shift parameters. The Peng-Robinson (PR) EOS is used with the van der Waals mixing rules. In the NM, pseudo components are initially assigned critical temperature (TC), critical pressure (PC), and acentric factor (ω) values that are optimized for the PR EOS for accurate phase behavior predictions for n-alkanes from C7 to C100. The subsequent regression process searches for an optimum set of TC, PC, and ω in physically justified directions. The regression algorithm developed does not require user's experience of thermodynamic modeling for robust convergence. The NM also satisfies Pitzer's definition of ω for each component.

The NM is compared with the CM in terms of various types of phase diagrams, minimum miscibility pressure calculations, and 1-D oil displacement simulations. Twenty two different reservoir oils are used in the comparisons. Results show that the NM with 11 components gives phase behavior predictions that are nearly identical to those using the CM with 30 components. A 1-D simulation case study presents that the NM can robustly reduce dimensionality of composition space while keeping accurate multiphase behavior predictions along composition paths at different dispersion levels tested. We show that the CM with volume shift can give erroneous phase behavior and oil recovery predictions in compositional simulation. The NM does not require volume shift to achieve accurate predictions of compositional and volumetric phase behaviors. The two types of phase behaviors are properly coupled in the NM.
Artificial Intelligence for Heavy Oil Assets: The Evolution of Solutions and Organization Capability
Authors: Popa Andrei S. , Cassidy Steve
Published: October 2012

Artificial Intelligence (AI) techniques have been successfully applied in the petroleum industry since the early 1990s initially attempting to solve simple tasks and more recently evolving into hybrid systems taking on complex optimization and modeling problems. Artificial Intelligence has become an integral part of our business in the last 10 years with applications ranging from reservoir characterization, production optimization to surrogate models used in reservoir simulation. Chevron's San Joaquin Valley Business Unit has been implementing AI technologies through Chevron's i-field™ program since 2003. With the majority of the production coming from heavy oil assets, most of the intelligent applications developed using AI target the optimization of thermal operations.

The paper describes the operator's experience and continuing efforts towards integration of Artificial Intelligence technologies in the Business Unit. The manuscript covers two topics: a review of several successful Artificial Intelligence applications implemented in the heavy oil assets while focusing on solutions and value creation, and an internal training program aimed at developing the company's organizational capability in this domain.

The first part discusses the successful implementation of AI techniques, neural networks, genetic algorithms, fuzzy logic, case- based reasoning and hybrid systems to solve complex projects. Case studies covering well candidate selection, optimization of cyclic steam scheduling, increased production opportunities identification, well failure diagnostic and job planning are presented. The review concludes with lessons learned, challenges and business value creation (increased production, NPV, time savings, etc). The second part highlights the efforts of initiating and implementing a training program aimed at building awareness and organizational capability. In 2009, a few AI enthusiasts and practitioners formed an Interest Group with the mission of enhancing reservoir management workflows by developing innovative solutions using Data Mining and AI technologies. The section describes the target audience, training material, workshops structure, brainstorming exercises and lessons learned from the sessions completed so far.

Ultimately, the review is intended to demonstrate the value of applying AI, and how to grow AI organizational capability. A brief overview of future plans concludes the paper.
Suitability of Horizontal, Inclined, and Vertical Wells on an Indian Offshore Platform Using Pressure Transient Analysis
Authors: Anand Abhijeet
Published: October 2012

The Indian offshore field under study has "LA" reservoir as one of the main producer. While the testing was carried out, nearly 20 wells were completed out of which 17 were on production, producing about 18,000 BOPD. "LA" reservoir is relatively clean and well developed in the crestal part of the reservoir. The average thickness of "LA" reservoir in the crestal part is 35-40m and increases upto 70m towards the flank. The Gas Oil Contact and Oil Water Contact are at 940m and 740m from MSL respectively. The IOIP and IGIP are of the order of 100.6 MMt and 2297 MMm3. In order to ascertain productivity of horizontal well, maximise oil recovery, prevent possible gas and water coning besides mastering of the technology, it was proposed to drill two horizontal wells.

This paper studies the Pressure Transient data of the Horizontal, Inclined and Vertical well of the same field. The interpretation of the horizontal well testing data was more complex due to development of shorter flow regimes. The data, however, is carefully analysed using the available software to determine several parameters including the average permeability and "k.h" product. The diagnostic derivative plots are used to determine the different flow regimes. Using the results, the permeability anisotropy and specific productivity was calculated for each well system. Replacement Ratio of horizontal to vertical/inclined well was determined using Newton's mid-pt numerical method and the cost analysis was done. Replacement Ratio and Cost ratio was combined for comparison of the three well systems.

Replacement Ratio was determined to be 2.25 which means 2.25 vertical wells may replace 1 horizontal well with same rate of production while Cost ratio for horizontal to vertical well was 2.40. On combining the two, it implied that horizontal well system was marginally more suitable in addition to other benefits for the given field with given conditions which in other words signifies that the horizontal well system's efficiency wasn't upto the desired level and needs severe improvement.