bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhanced Technology Transfer for Geothermal Exploitation Through a New Research Concept: The Geothermal Energy and High-Performance Drilling Research Program: gebo
Authors: Reinicke K. M. , Oppelt J. , Ostermeyer G. P. , Overmeyer L. , Teodoriu C. , Thomas R.
Published: June 2014

The government of Lower Saxony plans an extensive utilization of the geothermal potential in its subsurface for heat and electrical energy supply. The conditions to achieve this objective are quite favorable despite the moderate temperatures typical for the subsurface here: the geothermal potential below the surface of Lower Saxony is considerable, the knowledge of the geological subsurface in this oil and gas federal state is good, and the scientific and industrial infrastructure for exploring and developing the geologic subsurface is excellent.

The gebo research association unites the traditional strengths of the participating universities of the federal state of Lower Saxony and independent research institutions in geosciences, drilling technology, materials science, and technical systems. More than 40 scientists and engineers work together to develop and evaluate new concepts, materials, and devices. The gebo research association focuses on broad-scale, partially extremely high-risk problems in the "high-end" area of geothermal research; at the same time the participating industry is carrying out applied systems developments. Besides improving the economics of geothermal energy production and making it economically attractive in Lower Saxony, significant gebo "spinoff’ effects are expected to occur in industrial sectors, in particular from the materials and systems technology research.

The paper focuses on the concept of technology transfer through the gebo platform, as well as on its unique cooperation between seven project partners (research institutions), the industry partner, and the state of Lower Saxony. Also, the paper describes the objective, strategy, and organization of the research program gebo, which aims at improving the economics of geothermal energy recovery from deep geological strata by investigating new concepts and basic scientific work.
Methodology for Estimating Recovered Solvent in Solvent-Aided Process
Authors: Gupta Subodh C. , Gittins Simon , Canas Christian
Published: June 2014

The solvent-aided process (SAP) is a solvent-based enhancement of steam-assisted gravity drainage (SAGD) in which small amounts of solvent, such as light alkanes or natural-gas liquids, are added to the injected steam to enhance reservoir performance and associated project economics. Expectedly, the economics with SAP are sensitive to the solvent recovered from the reservoir, making its measurement in a field test an important factor.

When a single-component solvent such as butane, which is not generally present in the produced heavy oil or bitumen, is used in SAP, estimation of the recovered solvent can be achieved uniquely. But when the solvent also has heavier components, some of which overlap with the lighter components of the produced oil, the measurement is not straightforward. The problem is compounded by the fact that the interaction with the reservoir changes the composition of the produced solvent and makes it time variant on account of different resident times associated with different components. The issue is further complicated by the fact that produced oil also undergoes an in-situ solvent deasphalting process (SDA), which is also time and space variant in the reservoir. If there were no in-situ SDA, one potential method to measure the amount of produced solvent would be to measure the total asphaltene content as an oil "marker" in the produced blend. Use of a tracer with injected solvent, as well as regression-based analyses for solvent fraction (using compositional analyses of solvent, bitumen, and the blend) of the produced blend, is error prone for these same reasons.

Because of the issues in these approaches, a new method is desirable for a more-robust and unique assessment of the solvent amount in the produced fluids. This paper elaborates on the current challenges and proposes a couple of workable methods, including use of maltenes/metals content as oil markers as well as the use of boiling-point curves of the produced blend compared with the boiling point of the base oil.

Such techniques of estimating the recovered solvent can facilitate a more-objective assessment of SAP field tests and enable economic evaluation of SAP application to a commercial scale.
Foamy-Oil-Viscosity Measurement
Authors: Alshmakhy Ahmed , Maini Brij B.
Published: June 2014

Foamy-oil viscosity is a controversial topic among researchers regarding what happens to the oil viscosity when the solution gas starts coming out of solution because of decreasing pressure and the released gas starts migrating with the oil in the form of dispersed gas bubbles. For conventional oils, below the true bubblepoint pressure, the oil viscosity increases as the gas freely evolves from the oil. For foamy oils, it has been suggested that the apparent oil viscosity remains relatively constant or perhaps declines slightly between the true bubblepoint and a characteristic lower pressure, called pseudobubblepoint, which is the pressure at which the gas starts separating from the oil. Below this pressure, the viscosity increases, reaching the dead-oil value at atmospheric pressure. However, it is a well-known fact in dispersion rheology that the viscosity of dispersion is higher than the viscosity of the continuous phase. Therefore, the concept of foamy-oil viscosity being lower than the oil viscosity is counterintuitive. It is likely that the apparent viscosity for flow of foamy oil in porous media is not the true dispersion viscosity because of the size of dispersed bubbles being comparable to the pore sizes.

This study investigates this issue by measuring the foamy-oil viscosity under varied conditions. The effect of several parameters, such as flow rate, gas volume fraction, and type of viscometer employed, on foamy-oil viscosity was evaluated experimentally. Three different viscosity-measurement techniques, including Cambridge falling-needle viscometer, capillary tube, and a slimtube packed with sand, were used to measure the apparent viscosity of gas-in-oil dispersions. The results show that the type of measuring device used has a significant effect. The results obtained with Cambridge falling-needle viscometer correlate better with the observed behaviour in the sand-packed slimtube than the capillary viscometer results. Overall, the apparent viscosity of foamy oil was found to be similar to live-oil viscosity for a range of gas volume fractions.
Multioriented Fracturing in Unconventional Reservoirs Offers Improved Production by Better Connectivity
Authors: Surjaatmadja Jim B.
Published: June 2014

In the oil field, the term "unconventional" almost always means difficult to obtain for one or another reason. One reason addressed in this paper relates to formations characterized by the lack of permeable features that connect or can be easily connected to the wellbore using conventional stimulation techniques. The common logic of placing larger and larger fractures does work, but, when using this approach, the cost-to-reward ratio can be far from desirable.

It is well known that placing a second fracture sometime later in the life of a well will result in a fracture that extends in a slightly different direction, mostly caused by the drainage of the fluid near the fracture face. In this situation, fracture redirection is probably caused by the pore-pressure decline near the producing fracture face. In some instances, the new fracture produces almost as if it has reached a new formation.

This paper discusses placement of such second (or third) hydraulic fractures within the same time domain from the same wellbore section. While this has not yet been performed in the field, it is believed that the first fracture will modify the stress field to a perpendicular direction. Combined with the hypothesis of the hard-to-accept concept that fractures often shy away from the most-productive zones, this approach will cause the second fracture to extend directly into the more-productive zones, thus providing a substantial production boost.
Experimental Evaluation of SAGD/ISC Hybrid Recovery Method
Authors: Paitakhti Oskouei Seyed Javad , Maini Brij B. , Moore R. Gordon , Mehta Sudarshan A.
Published: June 2014

Most current in-situ recovery methods have limitations which restrict their application in many heavy-oil reservoirs. There is also a variety of undesirable environmental issues associated with existing thermal-recovery techniques. To overcome some of these problems, novel hybrid processes have been proposed that combine steam-assisted gravity drainage (SAGD) and in-situ-combustion (ISC) technologies. In the conventional ISC process, oil is displaced by an elevated-temperature combustion zone, but when the native oil mobility is low, this displacement becomes problematic because of the low oil mobility downstream of the combustion front. Heating the reservoir and reducing the distance between injector and producer can prevent such cold liquid blocking in the combustion process. This suggests that a well configuration that greatly decreases the distance between the injector and the producer (e.g., the SAGD well configuration) could be advantageous in ISC-based recovery methods. Moreover, running the SAGD operation in the initial period creates a vapour-filled depleted zone in the reservoir that would be sufficiently hot to start combustion on air injection. To investigate the feasibility of this idea, a hybrid experiment was conducted at a representative reservoir pressure. During the experiment, SAGD was operated in a physical model for a period and then combustion was started by switching from steam injection to air injection. A modified well arrangement was used to help the process operation, oil ignition, and combustion-front formation. Residual oil and water saturations in the model were analyzed. Also, core samples were extracted from the model to evaluate asphaltenes and coke formation. It was shown that it may be possible to recover nearly 70% of the original oil in place with a modified well arrangement.
Measuring the Reaction Rate of Lactic Acid With Calcite and Dolomite by Use of the Rotating-Disk Apparatus
Authors: Rabie Ahmed I. , Shedd Daniel C. , Nasr-El-Din Hisham A.
Published: June 2014

Lactic acid has been examined in various laboratories and applied in the oil field for acid fracturing and drilling-fluid-filter-cake removal, and as an iron-control agent during acid treatments. However, the reaction of lactic acid with calcite has not been addressed before. Determination of the reaction rate and the acid-diffusion properties is a critical step for successful treatments in matrix acidizing and acid fracturing. Therefore, the objective of this work is to conduct a detailed study on the reaction of lactic acid with calcite. Mass transfer and reaction kinetics are reported for the lactic acid/calcite system by use of the rotating-disk apparatus.

Disk samples were cut from Indiana limestone or Silurian dolomite and were used in the reaction-rate experiments. The effect of lactic acid concentration (1, 5, and 10 wt%), temperature (80–250°F), disk rotational speed (100–1,800 rev/min), and different inorganic salts on the reaction rate was investigated. The diffusion coefficient of 5 wt% lactic acid was determined at low disk rotational speeds and reported at 80, 200, and 250°F. A model that accounts for the effect of the kinetics of the surface reactions and the transport of reactants and products was developed. The activation energy and the rate constant at 80, 150, and 250°F for the reaction of lactic acid with Indiana limestone were reported. Reaction experiments of lactic acid with dolomite at 150°F over disk rotational speeds of 100–1,800 rev/min, and at 1,500 rev/min over a temperature range of 80–250°F, were conducted and the results were compared with those obtained for the calcite reaction.

At 80°F, the reaction of lactic acid with calcite was controlled by mass transfer at low disk rotational speeds (up to 500 rev/min) and was surface reaction limited at higher speeds. At higher temperatures (150, 200, and 250°F), both mass transfer and surface reaction influence the overall calcite dissolution. The kinetics of the surface reaction were influenced by both forward and backward reactions. At 80°F, the surface reaction contributes to 28% of the overall resistance. This dependence becomes much less (13 and 10%) at higher temperatures (150 and 250°F, respectively).

The reaction of lactic acid with dolomite at 150°F was mainly controlled by mass transfer up to 1,000 rev/min and by the kinetics of the surface reaction after 1,000 rev/min. At 80 and 150°F, the rate of reaction of lactic acid with calcite was an order of magnitude higher than that with dolomite. At temperatures of 200 and 250°F, the rate of reaction of lactic acid with calcite is twice the rate of reaction with dolomite. The presence of Ca2+, Mg2+, and SO42− ions reduced the reaction rate, which is most likely because of the reduction in the concentration gradient of the products. The reduction in the concentration gradient will cause a reduction in the rate of diffusion of the generated calcium away from the surface, and hence a lower rate of dissolution.
The Potential Pitfalls of Using North American Tight and Shale Gas Development Techniques in the North African and Middle Eastern Environments
Authors: Martin A.N.. N.
Published: June 2014

Many companies operating in the upstream gas industry in the Middle East and North Africa (MENA) are interested in the outstanding technical successes achieved by the US and Canadian tight and shale gas producers. It seems almost miraculous that companies can obtain significant gas-production rates from rocks with permeabilities measured in nanodarcies—so low, in fact, that permeability becomes almost impossible to assess accurately. In North America, the main factor now constraining shale gas production is the historically low gas price. Operators in MENA, who are accustomed to working in formations with permeabilities five or six orders of magnitude greater, have realized recently that they may be sitting on top of huge untapped gas reserves that had been evaluated previously as subeconomic.

In recent years, several major MENA-based operating companies have bought interests in US and Canadian tight and shale gas operations, with the objective of acquiring experience and technology that can be applied to similar formations in MENA and elsewhere. This seems to be an obvious and wise strategy; unfortunately, the problem is not the strategy, it is the tactics ("the devil is in the details"). In many instances, operating companies have been disappointed to discover that they cannot simply transplant an American-style development into MENA. Similarly, many North American independents have viewed the untapped low-permeability gas reserves of MENA as a natural territory for expansion, only to find themselves frustrated at almost every turn.

This paper seeks to highlight the potential pitfalls of trying to use North American development techniques in MENA, and to promote strategies and tactics that are more suitable. In addition, this paper will suggest structural changes that could have a significant positive impact on low-permeability gas developments in MENA.
A Numerical Study of Microscale Flow Behavior in Tight Gas and Shale Gas Reservoir Systems
Authors: Freeman C. M.
Published: June 2014

Tight gas and shale gas represent a significant energy resource. These types of reservoirs are geologically complex and the reservoir flow processes involved are unusual. While some investigators have modeled various aspects of these systems, there is currently no consensus on the significance of microscale diffusion on flow behavior over time. Pore throat diameters on the order of nanometers are known to result in non-Darcy flow conditions, which can be accounted for using the dusty-gas model coupled with various models for diffusivity estimation. This phenomenon is related to the Klinkenberg effect.

In this work we implement the dusty-gas model into a reservoir modeling tool based on the TOUGH+ code. We examine the effects of Knudsen diffusion on flowing gas composition at low permeability. We show that for rock with small pore throat diameters, the composition of flowing gas is significantly different than the in situ stagnant conditions. We describe how gas composition measurement could be used to identify flow boundaries in these reservoir systems. We present a fit-for-purpose numerical model based on the TOUGH+ code for modeling microscale transport effects.

This work contributes:

A new multicomponent microscale transport model A new, fit-for-purpose numerical model based on the TOUGH+ code capable of characterizing reservoir flow effects including permeability adjustment and diffusion in micro- and nano-scale porous media.
Optimizing BHA's Through Comparison of Conventional Drilling Methods to Use of Rotary Steerable Systems in the Barnett Shale
Authors: Goldsmith Jessica
Published: June 2014

The well that discovered the Barnett Shale was drilled in 1981. However, due to the complexity of this formation and lack of technology, it was not economically possible to drill this field at the time. It was not until the late 1990's that technology became available which allowed for economically viable drilling to be completed. Since then, the Barnett Shale has exploded and is the second largest producing gas field in the US behind the Panhandle-Hugoton field. As of February 2010, 246 operators were listed as working in the Barnett Shale field with13,740 wells on RRC records with 3,273 permitted wells. With the large number of operators, wells and new challenges in the area, it has become critical to find the best possible methods for drilling economically.

In this paper, an operator's conventional method of directional drilling using a steerable motor is being compared to trials of directional drilling using a rotary steerable system. The area of focus is Johnson County in the Barnett Shale (Fig 1). The operator began drilling in Johnson County in 2003. Until a few years ago, directional drilling was primarily completed using a steerable mud motor with either a fixed or adjustable bent housing and MWD. Rotary steerable tools were first tested in 2007, however, the trials covered in this paper began in 2009. One hundred percent of the wells drilled by the operator are horizontal. The typical well was drilled with a lateral less than 5,000 feet long. As drilling progressed, longer laterals were required. Due to surface location restrictions on a group of wells to be drilled, the laterals reached lengths of 6,000-7,000 feet. These lengths were necessary to drill under an urban area where surface locations were not available to accommodate shorter laterals. Torque and drag analysis was conducted to decide if conventional methods could be used. It was determined that conventional methods could not be used because of the potential for the drill pipe to buckle at the base of the curve and that rotary steerable tools must be used.
Reactivation Project
Authors: Borkhoche Roy
Published: June 2014

The reactivation project is a selection process to assess the value of inactive wells for the purpose of qualifying them or not as reactivation candidates. Engineering and economic criteria are incorporated into the selection process. The inactive wells studied belong to mature hydrocarbon fields located in West Texas. Primary field development dates to the early 20th century. Since then, infill drilling and various enhanced-oil recovery projects have been performed. Identification of reactivation candidates is important to realize the full potential of mature producing fields and to recover potentially bypassed pay. From a data set of 200 wells two reactivation candidates (wells A and B) were selected. The purpose of the paper will describe the selection process and focus on the well reactivation.

Several factors limit the recovery ratio from a given well. As the global demand for energy grows, petroleum companies will focus on the exploration and production of new hydrocarbon reserves. In the process of shifting resources from existing to newly-found fields, companies may neglect to realize the full potential of mature fields. Furthermore, engineering practices and tools of the past contribute to undermining recoverable reserves from a given reservoir. Advances in technology have led to improved field development strategies and optimum well recovery. Reactivation project applies current technologies for identifying and unlocking potential in inactive wells.

Based on the reactivation study, both wells A and B promise to increase reserves and add value. Well A is estimated to add recoverable reserves of 37 thousand bbl of oil and 372 MMcf of gas. Moreover, there is a contingency plan for well A. If reactivation of the lower zone is prevented by a major casing failure, then a shallow recompletion is proposed. The shallow zone is estimated to hold 534 MMcf of recoverable gas. On the other hand, well B evaluation indicates recoverable reserves of 30 thousand bbl oil and 89 MMcf gas. The two reactivations have a maximum potential of 145 thousand BOE and an associated net present value (NPV) of $1.92 million (reserve and NPV values do not include well A contingency plan).
Formation Damage Caused by Improper Mn3O4-Based Filter-Cake-Cleanup Treatments
Authors: Al Moajil Abdullah M. , Nasr-El-Din Hisham A.
Published: June 2014

Cleanup of filter cake is a difficult task and becomes more challenging when dealing with weighting materials [e.g., manganese tetraoxide (Mn3O4)]. Mn3O4 is a strong oxidizing agent and can be used as a catalyst because of its active phase, a nonstoichiometric Mn3O4 composed of an octahedral Mn2O3 phase and a tetrahedral MnO phase, which will result in complex interactions with most cleaning fluids. The reaction of selected organic acids and chelating agents with Mn3O4 particles as a function of time and temperature was studied. Solubility and compatibility tests of Mn3O4 particles with cleaning fluids were conducted using a high-pressure/hightemperature (HP/HT) see-through cell. Reaction kinetic tests were conducted using a three-neck round-bottom flask. Atomic absorption was used to measure manganese concentration, and X-ray diffraction was used to analyze solids remaining after the reaction. A white precipitate of manganese citrate was produced following the reaction of citric acid with Mn3O4 up to 284°F. The amount of precipitate was increased with temperature and initial acid concentration. An amino polycarboxylic acid chelating agent derived from L-glutamic acid (GLDA) (a chelant) reacted with Mn3O4 particles completely at 190°F. However, a large amount of a white was precipitate produced. Similarly, a white precipitate was observed with oxalic and tartaric acids. The reaction of diethylene triamine pentaacetic acide (DTPA) (a chelate) with Mn3O4 particles in a glass reactor produced Mn (silicates) at 212 and 284°F. The results of the present study will help drilling/completion engineers avoid using such cleaning fluids to prevent formation damage after filter-cake-removal treatments.
The Petrophysics of Problematic Reservoirs
Authors: Worthington Paul F.
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Introduction

Petrophysics provides the building blocks for integrated reservoir models. It encompasses the analysis of well logs run on wireline and drillstring, conventional and special core analysis, mud logging, and formation testing and fluid sampling. The subject has open- and cased-hole cultures. For deviated and horizontal wells, and/or in the presence of dipping beds, petrophysical analysis is 3D and it should account for formation anisotropy, particularly transverse/ longitudinal differences in rock properties where reference directions are relative to bedding. To manage the current task, the discussion notionally refers to water-wet reservoirs sensed by openhole well logs, although there are exceptions where the reservoir also is the source. Beyond this, the subject matter has been selected on the basis of topicality.

Petrophysical Evaluation

Most commonly, petrophysics is concerned with the technical evaluation of laboratory data and downhole measurements for reservoir properties such as shale-volume fraction Vsh, porosity f, permeability k, net/gross reservoir, water saturation Sw, and net/gross pay. The subject has a philosophy of indirectness, in that, often, it is not possible to measure a required reservoir property directly. Therefore, it is necessary to measure some other property that is related to the required property. For this reason, petrophysics is built around a framework of interpretive algorithms that relate measurable parameters to reservoir parameters. Usually, these algorithms are empirical with some conceptual reference. This means that quantitative petrophysical interpretation is, mostly, data driven and that the interpretive algorithms change from reservoir to reservoir. This, in turn, requires that each reservoir be investigated separately and thoroughly. For general formation evaluation, see Warner and Woodhouse (2007); for net-pay evaluation, see Worthington (2010a).

Archie Reservoirs. Petrophysical interpretive procedures usually are described in terms of an idealized clastic reservoir, which is the textbook reference and is sometimes termed an ’Archie?? reservoir because it broadly matches the requirements for the application of the fundamental Archie equations that provide the quantitative basis for welllog analysis (Archie 1942). Attributes of an Archie reservoir are listed in Table 1. Although these conditions were not itemized explicitly by Archie (1942), they are implicit in the use of the Archie equations on the basis of many years of application.
Don't Drop the Anchor: Recognizing and Mitigating Human Factors When Making Assessment Judgments Under Uncertainty
Authors: Sykes M. A. , Welsh M. B , Begg S. H
Published: June 2014

One of the most important tasks a petroleum geologist undertakes is to recognize and incorporate uncertainty concepts into their geologic interpretations and estimates of volumetric parameters. This is crucial, because the first requirement for sound decision-making is an accurate and unbiased evaluation of uncertainty in hydrocarbon volume estimations. Reducing uncertainty is a worthy, but secondary, objective. However, not only is the information upon which geologists make such judgments imperfect, incomplete and potentially biased, but the pernicious effects of certain human factors can amplify bias and create unrealistically narrow ranges.

A wide variety of human factors which influence such judgments have been revealed over recent years by applying psychological research techniques to geologic interpretation issues. Two of the most powerful and damaging cognitive effects are anchoring and overconfidence (Tversky & Kahneman, 1974).

Anchoring refers to the tendency for one piece of information, such as a "base case", to inappropriately constrain estimates. Overconfidence is the tendency to estimate ranges that are systematically too narrow with respect to the state of knowledge. Together, these result in inappropriately precise predictions of hydrocarbon volumes ranges, with a concomitant degradation in accuracy. The phenomena are found to be powerfully ingrained, even in the minds of experts (Morgan & Henrion, 1990; Northcraft & Neale, 1987; Welsh, Bratvold, & Begg, 2005), who frequently have a disproportionately large influence on the final estimates.

This paper describes and reports observations from both a program that ExxonMobil, with the Australian School of Petroleum, has embarked upon to increase awareness of these biases, and to develop tools to help mitigate their effects; and observations from the oil and gas industry as a whole. The ExxonMobil program is implemented through formal training and informal mentoring. Geologists are provided with exercises to test their natural predilection towards overconfidence, and susceptibility to being anchored. Upon revealing the influence of the bias, it is intended that the individuals take away an internalized caution against falling victim to these subtle traps in their future interpretations.

The durability of such learning is not necessarily permanent, however, and frequent reminders of the phenomena are imparted in order to reinforce and refresh. This is intended to inculcate mitigative behaviors in the members of the geological community over the long term.
Demonstrating Reasonable Certainty Under Principles-Based Oil and Gas Reserves Regulations
Authors: Sidle R.E.. E. , John Lee W..
Published: June 2014

Historically, oil and gas reserves definitions have included the term "reasonable certainty" when describing the standard of high confidence/low uncertainty for a conservative estimate of future recovery from an accumulation. In 2008, the US Securities and Exchange Commission (SEC), one source for such definitions and regulations, changed its rules on oil and gas reserves and moved from a more rules-based approach to a more principles-based approach. While the SEC regulations both before and after this change incorporated the term "reasonable certainty," the philosophical change from rules-based to principles-based regulation puts more responsibility on the reserves evaluator to understand the uncertainties in the reserves estimation and to "get it right."

This paper examines the stated definition of reasonable certainty as well as the effective definition based on how the regulations were interpreted under the prior rules-based system. Examples of prior methods of regulatory controls, under a rules-based system, that no longer fit under a principles-based system are noted. The paper then examines the current definition. The overprint of a principles-based regulatory system must be considered to understand how such an approach will impact the effective definition under the current rules. The insights from the financial and legal communities are examined for their learnings in which other forms of regulations underwent this same philosophical change. This examination describes how rules-based systems are more "input control" focused, while principles-based systems focus more on "outcomes."

Next, the paper suggests how the reserves evaluator should apply this understanding of the new principles-based rules. The evaluator is now more responsible to understand the range of uncertainty in reserves estimates and to ensure that the outcome (the proved reserves estimate) satisfies the regulations. Also, the paper discusses key tests to demonstrate that the correct outcome— a reasonably certain volume—has been achieved. After 30 years of well-established practices, the responsible reserves evaluator has examined changes as they evolved in then-current regulation text. Now, the evaluator needs to additionally consider changes based on the implications of principles-based regulations.
A Comparative Study of Transient and Steady-State Three-Phase Oil Permeability
Authors: Dehghanpour Hassan , DiCarlo David A.
Published: June 2014

Relative permeabilities for three-phase flow are commonly predicted from two-phase-flow measurements using empirical models. These empirical models are usually tested against available steady-state data. However, the oil flow is transient during various production stages [e.g., gas injection after waterflood and steamassisted gravity drainage (SAGD)]. Hence, there is a need to test the empirical models against unsteady-state or transient data. We compare two sets of three-phase oil-permeability data measured during tertiary gasflood. The first data set, which was recently published (Dehghanpour et al. 2011a), is measured during transient gravity-drainage experiments, and will be detailed further here. The second set was measured by Oak et al. (1990) during steady-state corefloods. We compare the two data sets with the corresponding two-phase permeability curves, and observe different qualitative behaviours. The comparison indicates that during steady-state tertiary gasflood, the presence and flow of water restrict the oil flow, while during transient tertiary gasflood, water-saturation drop enhances the oil flow. We test the performance of well-known empirical models further in predicting the two data sets, and explain how Stone I and saturation-weighted interpolation (SWI) should be used to usefully predict oil permeability during a three-phase tertiary displacement.
A Parametric Simulation Study for Solvent-Coinjection Process in Bitumen Deposits
Authors: Yazdani Ali , Alvestad Jostein , Kjoensvik Dagrun , Gilje Eimund , Kowalewski Espen
Published: June 2014

In-situ extraction of ultraviscous deposits from the vast bitumen resources in western Alberta, Canada, requires significant water and energy usage, which consequently leads to greenhouse-gas emissions. Currently proven steam-based recovery schemes include cyclic-steam-stimulation (CSS), steamflooding, and steam-assisted gravity-drainage (SAGD) processes, which are accompanied by many economic and environmental challenges. Coinjection of solvent with steam is a technology that has the potential to improve the efficiency of steam processes as well as reduce energy usage and carbon dioxide emissions.

In recent years, researchers and industry professionals have attempted to develop the process further by conducting fundamental research as well as field pilot trials, with varying degrees of success. However, the current level of understanding of the process and the knowledge surrounding the fundamental physics and mechanisms involved are not entirely satisfactory.

In this paper, a parametric simulation study was performed to address the key aspects of the solvent-coinjection (SCI) process that contribute to further understanding and development of the process. Simulation observations were verified with experimental evidence where available to support the results and conclusions. Effects of several operational and geological parameters were evaluated on the performance of the SCI process, and the relative performance benefits were assessed over normal SAGD operations. These parameters included solvent type, solvent concentration, initial-solution gas/oil ratio (GOR), relative permeability curves, and pay thickness.

The results revealed that the optimal solvent should not be chosen only on the basis of mobility-improvement capability, but also under consideration of other operational, phase- and flow-behavioral and/or geological conditions that are set or present. Higher concentrations of solvents showed more energy-saving upsides than rate-acceleration benefits. It was also observed that the reservoir steam-intake rate is still likely to be the prime performance indicator of the SCI process. In addition, SCI showed that the potential exists for accessing more resources, particularly below the producer level. Furthermore, steam trap control on the producer seems to be problematic when used for SCI simulation. With the current well-control capacity of simulators, a higher degree of subcool is likely to be needed to avoid live vapor-phase production from the producer.
Design of Solvent-Assisted SAGD Processes in Heterogeneous Reservoirs Using Hybrid Optimization Techniques
Authors: Al-Gosayir Muhammad , Leung Juliana , Babadagli Tayfun
Published: June 2014

Numerous steam-assisted gravity-drainage (SAGD) optimization studies published in the literature combined numerical simulation with graphical or analytical techniques for design and performance evaluation. Efforts have integrated the simulation exercise with global optimization algorithms. Some studies focused on optimization of cumulative steam/oil ratio (cSOR) in SAGD by altering steam-injection rates, while others focused on optimization of net cumulative energy/oil ratio (cEOR) in solvent-additive SAGD by altering injection pressures and fraction of solvent in the injection stream. Several studies also considered total project net-present-value (NPV) calculation by changing total project area, capital-cost intensities, solvent prices, and risk factors to determine the well spacing and drilling schedule. Optimization techniques commonly used in those studies were scattered search, simulated annealing, and genetic algorithm (GA). However, applications of hybrid GA were rarely found.

In this paper, we focused on optimization of solvent-assisted SAGD using various GA implementations. In our models, hexane was selected to be coinjected with steam. The objective function, defined on the basis of cSOR and recovery factor, was optimized by changing injection pressures, production pressures, and injected solvent/steam ratio. Techniques, including orthogonal arrays (OA) for experimental design (e.g., Taguchi's arrays) and proxy models for objective-function (F) evaluations, were incorporated with the GA method to improve computational and convergence efficiency. Results from these hybrid approaches revealed that an optimized solution could be achieved with less central-processing-unit time (e.g., fewer number of iterations) compared with the conventional GA method. Sensitivity analysis was also conducted on the choice of proxy model to study the robustness of the proposed methods.

To investigate the effects of heterogeneity in the design process, optimization of solvent-assisted SAGD was performed on various synthetic heterogeneous reservoir models of porosity, permeability, and shale distributions. Our results highlight the potential application of the proposed techniques in other solvent-enhanced heavy-oil-recovery processes.
Solvent-Chamber Development in 3D-Physical-Model Experiments of Solvent-Vapour Extraction (SVX) Processes With Various Permeabilities and Solvent-Vapour Qualities
Authors: Knorr Kelvin D , Imran Muhammad
Published: June 2014

Solvent-vapour extraction (SVX) processes offer an attractive alternative to thermal recovery processes by being less energy intensive and are more suitable for thinner, partially depleted reservoirs. A typical SVX process uses solvent injection to dilute the heavy oil by reducing its viscosity, allowing it to be mobilized for production. During this process, the injection of hydrocarbon solvents results in partial deasphalting of the heavy oil, thus reducing its viscosity and enhancing the process performance further.

This work examined the formation and growth of solvent chambers in laterally and vertically spaced horizontal injector/producer well pairs in porous media with five different permeabilities and three different solvent-vapour qualities. Consolidation of the porous media caused by asphaltene precipitation was also analyzed. Thermal-imaging and model excavation studies were performed to investigate the formation and growth of solvent chambers for seven different experiments conducted on a large 3D-physical-model apparatus.

The important findings from this study are as follows: During solvent injection, one or more solvent fingers develop between the injector and producer. The dominant solvent finger becomes a conduit that grows into a solvent chamber connected to the injection well in the upper portion of the reservoir, and develops into an oil-drainage conduit connected to the production well in the lower portion of the reservoir. Solvent dispersion layers are located on the margins of both the solvent chambers and the oil-drainage conduits. The location and development of these nonuniform solvent chambers and oil-drainage conduits are unpredictable, and the oil-drainage conduits do not grow significantly in diameter once connected to the production wellbore, limiting the wellbore inflow efficiency and conformity. Asphaltene precipitation and migration can aggravate this inflow problem, reducing the SVX process performance further.

SVX performance can be improved by increasing the number and diameter of oil-drainage connections between the solvent chamber and the production well, and by controlling the oil deasphalting process. This can be performed by optimizing injection- and production-wellbore geometries, and by optimizing solvent-injection rates and vapour quality.
Effect of Natural-Fracture Density on Production Variability of Individual Wells in the Nikanassin Tight Gas Formation
Authors: Gonzalez Laureano , Aguilera Roberto
Published: June 2014

A statistical model with a strong correlation has been developed to determine average fracture density (FD) on the basis of production variability of 271 individual wells producing exclusively from the Nikanassin and equivalent formations in a large area of more than 15 000 km2 in the western Canada sedimentary basin (WCSB) in Alberta and British Columbia. Fractional production-variability plots (FPVPs) published by Nelson (2001) have been used successfully in the past in many naturally fractured reservoirs around the world. Up to now, the generation of such graphs has been based on empirical observations from field-production data. The variability of the graphs is interpreted qualitatively as a measure of reservoir heterogeneities. This paper presents a sequential methodology to reproduce empirical fractional variability plots of the Nikanassin tight gas formation using real data, an empirical variability-distribution model (VDM), and dual-porosity numerical simulation. Different simulation approaches and multiple sensitivities were generated from the simplest to the most-detailed cases to understand what causes the curvature of the FPVP in Nikanassin wells. The base simulation case is a homogeneous dual-porosity model, where porosity and permeability are set constant for matrix and fractures. A second case accounts for a heterogeneous dual-porosity model generated through statistical distributions of porosity and permeability. Finally, discrete-fracture-network (DFN) methodology is used to generate multiple fracture models from which stochastic fracture properties are generated for the simulation model. It is concluded that curvature of the variability plot is affected mainly by the occurrence of natural-fracture density. This finding permits estimating FD approximately parallel to the northwest/southeast-trending thrust belt of the Canadian Rocky Mountains in both the west and the east side of the deformation wedge. An unexpected result is that for a significant change in fracture permeability and porosity with constant FD, the fractional production-variability curve is not affected significantly in the case of gas reservoirs. Although the method is applied specifically to the Nikanassin tight gas formation, the theory is developed in detail in such a way that the methodology can be applied in other tight gas reservoirs around the world. Findings from this work are in good agreement with the geological description of the Nikanassin formation and with a production analysis performed in six Nikanassin study areas based on the cumulative number of wells vs. yearly cumulative gas production.
Effective Caprock Determination for SAGD Projects
Authors: Collins Patrick M. , Walters Dale A. , Perkins Thomas W. , Kuhach Joseph D. , Veith Edwin J.
Published: June 2014

In the oilsands of western Canada, caprock integrity has become a central issue in projects using steam-injection-recovery processes such as steam-assisted gravity drainage (SAGD). Caprocks contain steam and fluids within the reservoir; therefore, understanding the integrity of the caprock over the life of the operation is critical in order to ensure a safe and economically viable project. A multidisciplinary study was undertaken to evaluate geological facies as potential caprock for Ivanhoe Energy's Tamarack project. This examination of the historical performance of operating SAGD projects correlated the maximum vertical growth of the steam chamber with geology and the steam-injection operating pressure. The study found that SAGD steam chambers are being constrained by geological facies grading upward to poorer reservoir quality, rather than being constrained by shallower, regionally extensive, massive, low-permeability barriers. Geomechanical reservoir simulations of Ivanhoe Energy's proposed Tamarack SAGD project predict that the steam chamber will be constrained similarly as reservoir quality degrades upward. The simulations show the pressure and stress gradients in the formations above the steam chamber as a function of time and operating conditions, allowing for a more accurate assessment of steam containment and the risk for shear and/or tensile failure. The findings are significant because they confirm that the vertical growth of SAGD steam chambers has been halted, in effect, by facies consisting of interbedded sands and mudstones. These effective caprock facies have higher fracture pressures than the regionally extensive low-permeability barriers because these facies are found at greater depths. The higher fracture pressure justifies a higher maximum operating pressure, with its associated higher reservoir temperatures resulting in much lower bitumen viscosities. As a result, SAGD well productivity and project economics are greatly improved, particularly for shallow SAGD projects.
SAGD-Pair Performance Optimization: A Field Case Study of Recovery Enhancement
Authors: Jorshari Kamran , O'Hara Brendan , Jones Ramsey
Published: June 2014

Performance of fields under thermal recovery processes has been improved considerably by experimenting with new techniques and innovative operational solutions in heavy-oil and extra heavy oil fields (Butler 1994; Singhal et al. 1998). By far, steam-assisted-gravity-drainage (SAGD) and cyclic-steam-stimulation (CSS) methods have been the most compelling and have shown a successful history in these oil fields (Butler et al. 2000; Butler 2001). At the Celtic heavy-oil field, Husky Energy experienced three phases of optimization over the course of 10 years of recovery. The Celtic field consists of 28 SAGD pairs located in the Lloydminster heavy-oil region that have been in service since 2001. Among these pairs, there are three SAGD pairs (F Pad East) with early productivity challenges in addition to downtime caused by sand production. Following new geological realization and reservoir studies, the injector wells were converted to production wells performing a horizontal CSS process. In 2008, and in an effort to maintain production, a detailed numerical-simulation study was conducted to compare different steam support configurations and the result was justified for field execution. The outcome resulted in four directional steam-injection wells (G Pad) permanently started to support the current horizontal producers. In 2009, the new configuration commenced and is still in operation today. Communication with horizontal wells has been confirmed on one side of the pattern, and it has been extending gradually to the other side as it was investigated in other work (Edmunds 1991; Al-Salhi et al. 1997). Recently, acquired field data suggest that the process is exceeding the expected oil profile and its steam consumption is less than anticipated. The geological review, history of the F Pad East pairs, results of numerical-simulation study, and recommendations are presented in this paper.