bluuebunny/crossref_metadata_2025 huggingface dataset:
Chlorine Logging in Cased Holes
Authors: Dewan J.T. , Stone O.L. , Morris R.L.
Published: June 2014

A new chlorine logging tool, developed primarily for the detection of oil saturation behind casing, is described. The principle involved is the selective detection of gamma radiation from neutron capture in chlorine. The tool is relatively insensitive to porosity, responding mainly to the concentration of chlorine in the interstitial liquid rather than to the total chlorine content in the formation.

A brief review of the fundamentals of chlorine logging is given. This includes a discussion of the partition of neutron captures in clean sand and limestone formations, and the spectra of gamma rays obtained. The effect of neutron capture in iron is shown to be important.

Following a short description of the logging tool, the laboratory-determined response of the instrument in cased sandstone formations is presented. It is shown that better results can be obtained by logging in empty casing than in casing filled with oil, fresh water, or salt water. Effects of neutron capture in the casing, casing liquid, cement annulus and formation matrix are discussed.

A method of interpreting the Chlorine log, based on the use of the response curves, is explained. This is illustrated with several field examples which also show comparisons of electrical and Chlorine logs. In Gulf Coast formations, the Chlorine log often bears a marked resemblance to the SP curve, and in some cases water-oil contacts have been identified by a visual comparison of the two curves. Comparison of the Chlorine log with a neutron log is also valuable in interpretation. The role of the neutron log is to give a porosity (which need be approximate only), to indicate formation shaliness and, most important, to identify gas which is generally indistinguishable from oil on the Chlorine log.

The Chlorine log should prove most useful in old wells where adequate open-hole logs do not exist, or where saturation conditions in the producing zone have changed. The combination of the Chlorine log with a Cement Bond log and the wireline formation tester should aid materially in successful reworking of such wells.
Natural Gas Hydrates at Pressures to 10,000 psia
Authors: McLeod Harry O. , Campbell John M.
Published: June 2014

This paper presents the results of the data obtained in the first stage of a long-range study at high pressures of the system, vapor-hydrate-water rich liquid-hydrocarbon rich liquid. The data presented are for the three-phase systems in which no hydrocarbon liquid exists. Tests were performed on 10 gases at pressures from 1,000 to 10,000 psia. One of these was substantially pure methane, and the remainder were binary mixtures of methane with ethane, propane, iso-butane and normal butane.

Several conclusions may be drawn from the data.Contrary to previous extrapolations, the hydrocarbon mixtures tested form straight lines in the range of 6,000 to 10,000 psia which are parallel to the curves for pure methane, when the log of pressure is plotted vs hydrate formation temperature.The hydrate formation temperature may be predicted accurately at pressures from 6,000 to 10,000 psia by using a modified form of the Clapeyron equation. The total hydrate curve may be predicted by using the vapor-solid equilibrium constants of Carson and Katz to 4,000 psia and joining the two segments with a smooth continuous curve between 4,000 and 6,000 psia.The use of gas specific gravity as a parameter in hydrate correlations is unsatisfactory at elevated pressures.The hydrate crystal lattice is pressure sensitive at elevated pressures.

Introduction

Prior to 1950 many studies had been made of the hydrate forming conditions for typical natural gases to pressures of 4,000 psia. Most of these attempted to correlate the log of system pressure vs hydrate formation temperature, with gas specific gravity as a parameter. One of the more promising correlations was made by Katz, et al, which utilized vapor-solid equilibrium constants. The only published data above 4,000 psia are those of Kobayashi and Katz for pure methane to a pressure of 11,240 psia. In the intervening years, most published charts for the high-pressure range have represented nothing more than extrapolations of the low-pressure data, with the methane line serving as a general guide. The reliability of these charts has become increasingly doubtful (and critical) in our present technology as we handle more high-pressure systems.
Theory of Formation Cutting Using the Sand Erosion Process
Authors: Brown Robert Wade , Loper Jack L.
Published: June 2014

The process of sand erosion has been harnessed to perform a useful function-the directed perforating of oilfield tubular goods and formation rock. In this process the sand is carried by a liquid medium and the resulting slurry is forced through a nozzle at an extremely high velocity. Upon impingement against casing or formation, the fast-moving sand particles erode a perforation in the casing followed by cavity formation in the medium behind the casing. The many factors influencing the rate and extent of this penetration are inherently difficult to establish experimentally. Equations describing submerged jet behavior have been applied to these conditions. The following paper develops the equations for predicting the performance of the perforating jet.

Introduction

The cutting power of high-velocity sand has been well known in the petroleum industry for many years. Sand carried by a high-velocity gas stream causes severe erosion. This effect has been the cause of numerous production problems in certain areas.

It was logical to expect that this phenomenon would one day be adapted to useful industrial applications. Development of mobile, high-pressure, high-horsepower pumping equipment in the last decade has made this possible.

The sand erosion process involves pumping a fluid containing abrasive solids through a set of nozzles at a high differential pressure (2,000 to 4,000 psi). The pressure conversion into kinetic energy imparts high velocity to the sand particles which, upon impact with the formation face or casing wall, erode the material in an organized pattern.

This paper attempts to establish the effects of the various parameters and to predict the performance and limitations of the process. The following factors will be considered: nozzle differential pressure, perforation size, sand concentration, nozzle stand-off distance and back-pressure. In general, this discussion is presented along theoretical lines and is substantiated by field results and data where reliable field data exists.
Characterization of the San Miguel Sandstone by A Coordinated Logging and Coring Program
Authors: Knutson C.F. , Conley F.R. , Bohor B.F. , Timko D.J.
Published: June 2014

Analyses of the cores and logs from 12 core test wells randomly spaced about a producing well showed that the average producing-zone rock properties are rather uniform within a single well's drainage area.

The dense zones have a limited horizontal continuity. They form barriers to vertical fluid migration which generally are not effective areally over distances greater than 50 ft.

Introduction

The petroleum engineer is frequently faced with the problem of characterizing a reservoir to aid in development or production operations. In general, two approaches are used -all the available data may be lumped and one specific "average" value obtained for each parameter, orthe datum points may be assigned coordinates and the system characterized by an array of values throughout a space frame.

In following this second course, the variation in the parameters is a critical factor.

Everyone is aware of the very small fraction of the reservoir which can be sampled. In this characterization of the San Miguel–1 sand, Sacatosa field, Maverick County, Tex. (see Fig. 1) with data obtained from a coordinated coring and logging program, this small sample limitation has been handled by dividing the apparent formation variation into four components:inherent measuring variations,wellbore variations,well drainage area variations, and (4) field-wide variations in rock properties.

Data on each of these components are presented in the following sections.
Validation of Predicted Cumulative Sand and Sand Rate Against Physical-Model Test
Authors: Rahmati Hossein , Nouri Alireza , Vaziri Hans , Chan Dave
Published: June 2014

This paper presents a numerical model to study the onset and rate of sand production and compares its predictions against physical-model testing data on Salt Wash South (SWS) sandstone. A reliable sand-prediction tool is essential in sand-production management. It enables engineers to improve well-completion design, with the aim of maximizing well productivity without compromising well integrity.

A sanding test on a weakly consolidated sandstone sample was numerically simulated using a finite-difference-based numerical model. The model is based on erosional mechanics in which coupling between fluid flow and mechanical deformation captures some of the key mechanisms that are involved in sand production. Sand is assumed to be produced when the material is fully degraded and hydrodynamic forces are high enough to remove the particles.

The outcome of the numerical model shows a reasonable agreement against perforation-test results in terms of the onset and rate of sand production. The model shows that sand production initiates from the perforation tip and propagates to the top and sides of the perforation cavity. The sanding rate increases at higher flow rates. Furthermore, the model predicts external deformations of the sample, which are in close agreement with the experimental observations.
Pressure-Transient Behavior of Continuously and Discretely Fractured Reservoirs
Authors: Kuchuk Fikri , Biryukov Denis
Published: June 2014

Fractures are common features of many well-known reservoirs. Naturally fractured reservoirs contain fractures in igneous, metamorphic, and sedimentary formations. Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to many fractures with varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (i.e., not a connected-network fracture system). New semianalytical solutions are used to understand the pressure behavior of naturally fractured reservoirs containing a network of discrete and/or connected (continuous) finite- and infinite-conductivity fractures. We present an extensive literature review of the pressure-transient behavior of fractured reservoirs. First, we show that the Warren and Root (1963) dual-porosity model is a fictitious homogeneous porous medium because it does not contain any fractures. Second, by use of the new solutions, we show that for most naturally fractured reservoirs, the Warren and Root (1963) dual-porosity model is inappropriate and fundamentally incomplete for the interpretation of pressure-transient well tests because it does not capture the behavior of these reservoirs.

We examined many field well tests published in the literature. With few exceptions, none of them shows the behavior of the Warren and Root (1963) dual-porosity model. These examples exhibit very diverse pressure behaviors of discretely and continuously fractured reservoirs. Unlike the single derivative shape of the Warren and Root (1963) model, the derivatives of these examples exhibit many different flow regimes depending on fracture distribution and on their intensity and conductivity. We show these flow regimes with our new model for discretely and continuously fractured reservoirs. Most well tests published in the literature do not exhibit the Warren and Root (1963) dual-porosity reservoir-model behavior. If we interpret them by use of this dual-porosity model, then the estimated permeability, skin factor, interporosity flow coefficient (λ), and storativity ratio (ω) will not represent the actual reservoir parameters.
Management Systems Approach to Managing Human Rights Issues
Authors: Nguyen Tam , Herzog Gabriella , Fokkema Bert , Vallat Julie , Cleland Roper
Published: June 2014

There has been a proliferation of external guidance and guidelines for managing human rights issues. While these are useful tools to inform the management of potential risk, at best they may offer abstract concepts or aspirations of performance. In many respects, existing management systems and processes have the requisite components to identify, assess, prevent and/or manage potential human rights issues. The paper will examine existing management systems in oil and gas companies for addressing potential human rights issues.

The purpose of the paper is to describe how IPIECA, the global oil and gas industry association for environmental and social issues, has responded to the emergence of external guidelines in connection to designing and implementing the due diligence process consistent with the United Nations (UN) Guiding Principles on Business and Human Rights.
Stability of In-Situ-Combustion Process to Stoppage of Air Injection
Authors: Turta Alexandru T.
Published: June 2014

Unlike steam injection for heavy-oil recovery, the in-situ-combustion (ISC)process requires an extra step--namely, the initiation of the process, theso-called ignition operation. During ignition, an ISC front is generated nearthe air-injection well and, thereafter, this front is propagated towardproduction wells. Air-injection interruptions can be unintentional orintentional, including scheduled interruptions for 1 day per month for cleaningoil from air lines exiting the compressors. Regarding air-injectioninterruptions, one question arises: Can the process be resumed withoutinitiating a new ignition operation? This paper attempts to provide answers tothis question. The paper reviews information on 10 cases of air-injectionstoppage in the field, involving well-instrumented dry ISC projects, conductedeither in patterns or in a line-drive system. Most of the cases are from theSuplacu de Barcau (Romania) project, which is the world's largest ISCcommercial project. The duration of air-injection interruptions ranged from afew hours to 42 days. Performance before and after interruptions is analyzed interms of changes in air injectivity, effluent-gas composition, and oilproduction. To support various field observations, essential results fromsimulation of the dry ISC process are also included; temperature distributionsduring air-injection stoppage were determined analytically for a linear systemand numerically for a radial system. In both cases, a specific characteristicof the temperature redistribution was noted: the move/shift of the peaktemperature inside the former burned-out zone. Some additional conclusionsregarding the stability of the process as a function of elapsed time since theinitiation of the process were also formulated. Stability of the process wasinvestigated for air-injection interruptions lasting up to 40 days.
A Comparative Study on WAS, SWAS, and Solvent-Soak Scenarios Applied to Heavy-Oil Reservoirs Using Five-Spot Glass Micromodels
Authors: Farzaneh Seyed Amir , Dehghan Ali Akbar , Ghazanfari Mohammad H. , Kharrat Riyaz
Published: June 2014

In this work, a series of solvent- and water-injection scenarios were conducted on horizontal five-spot glass micromodels that were saturated initially with heavy oil. Sandstone and limestone rock look-alike and network patterns with different pore structures were used in the experiments. The results show that the ultimate oil recovery of a water-alternating-solvent (WAS) scheme was greater than that of a simultaneously water-alternating-solvent (SWAS) scheme, and the efficiency of a solvent-soak scheme also offers a greater recovery. Likewise, the WAS scheme resulted in greater oil recovery when compared with continuous solvent injection (CSI), with the same amount of solvent consumption. Furthermore, some pore-scale phenomena, such as viscous fingering, diffusion of solvents into heavy oil, and localized entrapment of oil and solvent because of heterogeneity and/or water blockage, are also illustrated. The results of this work can be helpful for better understanding and verification of flow transport and pore-scale events during different solvent-based-injection scenarios in heavy-oil reservoirs.
Framework Increases Effectiveness of M&A Teams When Acquiring, Validating and Analyzing Information from Data Rooms
Authors: Harrison Bob
Published: June 2014

Data rooms are inevitable whenever companies desire to acquire or divest oil and gas assets. They can be physical, i.e. a secure room with data placed within it, or virtual, i.e. an online data archive that can be accessed via a secure web portal, or a combination of both. If the data room visit by the prospective buyer's Mergers and Acquisitions (M&A) team lacks the necessary forethought and planning, it may not achieve its objective and the potential deal may be delayed, or even not go ahead at all.

This paper presents a framework to enable quicker evaluation of potential investments, while ensuring due diligence is taken when auditing estimates of resources and reserves. The framework is created for M&A teams with a wide range of experience and expertise, from newcomers to those who have spent too many hours in them.

Examples of real-life data room situations are given to illustrate how the framework is implemented. Advice is given on what data are essential to acquire versus those that are nice to have, depending on what the prospective buyer wishes to achieve. The challenge of selecting the appropriate make-up of the M&A team is also addressed. The framework gives clear and concise advice on what team members should do before, during and after the data room visit. Prioritized data lists are provided for each M&A team member, specific to their technical discipline, and key investigative questions to ask the seller are suggested. Time-saving ideas are proposed that can speed up any valuation in order that prospective buyers can quickly assess opportunities.

Finally, the paper describes some pitfalls that are inherent in any oil and gas asset evaluation, but which may have been avoided if the framework had been followed.
Experimental Investigation of Bitumen Recovery From Fractured Carbonates Using Hot Solvents
Authors: Pathak Varun , Babadagli Tayfun , Edmunds Neil
Published: June 2014

With the decrease in conventional oil and gas reserves throughout the world and an ever-increasing demand for fossil-fuel-based energy and resulting high oil prices, focus has been shifting to unconventional and heavy oil and bitumen. Grosmont carbonates in northern Alberta have been estimated to contain at least 300 billion bbl of heavy oil or bitumen. However, recovering this oil is extremely difficult because of the complexity associated with carbonate reservoirs in general (e.g., the Grosmont unit is known to possess a triple-porosity system of matrix, fractures, and vugs, on the basis of core studies). The second problem is the fluid itself, which is highly viscous bitumen that is immobile at reservoir conditions. To extract this bitumen from heterogeneous carbonate rock, both heat and dilution using solvents may be needed. This paper reports the results and analysis of hot-solvent experiments conducted on original Grosmont carbonate cores. Three experiments were conducted using propane and one using butane as solvent. After heating the entire system containing the core sample, solvent gas was injected. The rock was allowed to soak in the hot solvent for a long time. The experimental temperature and pressure were decided on the basis of the results of our earlier work that suggested they be slightly above the saturation line of the particular solvent. An attempt was made to keep the conditions close to the saturation conditions of the solvent being used to maximize the dilution and, hence, the recovery. The oil produced was analyzed for viscosity and asphaltene content. The results in terms of recovery, the degree of dilution, and upgrading achieved suggested that butane was a better solvent for this bitumen. Finally, the optimum conditions for operation of the hot-solvent process were verified for Grosmont carbonates.
3D Modeling of Multistage Hydraulic Fractures and Two-Way-Coupling Geomechanics/Fluid-Flow Simulation of a Horizontal Well in the Nikanassin Tight Gas Formation, Western Canada Sedimentary Basin
Authors: Gonzalez Laureano , Nasreldin Gaisoni , Rivero Jose , Welsh Pete , Aguilera Roberto
Published: June 2014

Unconventional gas is stored in extensive areas known as basin-centered continuous-gas accumulations. Although the estimated worldwide figures differ significantly, the consensus among the studies relating to unconventional gas resources is that the volumes are gigantic. However, the low permeability in these types of reservoirs usually results in a very low recovery factor.

To help unlock these resources, this paper presents a new and more accurate way of simulating multistage hydraulic fracturing in horizontal wells in three dimensions by use of single- and dual-porosity reservoir models. In this approach, the geometry (not necessarily symmetric) and orientation of the multiple hydraulic fractures are driven by the prevailing stress state in the drainage volume of the horizontal well. Once the hydraulic-fracturing job is accurately modeled in three dimensions, two-way geomechanical coupling is used to history match the produced gas from a horizontal well drilled in the Nikanassin naturally fractured tight gas formation of the Western Canada Sedimentary Basin (WCSB).

Traditionally, the most widely used approaches have their roots in semianalytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from a line source of injection. In contrast, the computed results presented in this study show that the incorporation of geomechanical effects gives a more realistic representation of the orientation and geometry of hydraulic fractures. Reduction in permeability of the natural and hydraulic fractures because of pressure depletion results in more-realistic production predictions compared with the case in which geomechanical effects are ignored.

The telling conclusion, in light of the computed results, is that the field of hydraulic fracturing provides an object lesson in the need for coupled 3D geomechanical approaches. The method presented in this paper will help to improve gas rates and recoveries from reservoirs with permeability values in the nanodarcy scale.
Criticality Testing of Drilling-Fluid Solids-Control Equipment
Authors: Aase Bodil , Omland Tor Henry , Jensen Ellen Katrine , Vestbakke Anne Turid , Knudsen Bjarte Sivert , Haldorsen Frode , Nysted Arvid , Storslett Eystein Ove , Steinnes Iren , Eliassen Einar Knut , Enger Jørund , Lie Øyvind , Peikli Vegard
Published: June 2014

Correct selection and use of solids-control equipment are essential in not only maintaining drilling fluid at its desired properties but also in avoiding the generation of unnecessary waste streams during drilling.

Since the early 1930s, the shale shaker has been the dominant device for primary-solids removal. Additional equipment (e.g., desilters, desanders, and centrifuges) was often used in the past to maintain proper solids control, but experience in recent years has demonstrated that, although dependent on correct operational procedures, several types of shale shakers have sufficient performance to act as the sole solids-control devices without the use of desanders and desilters.

Despite often being the only measure for solids removal, the selection of shale shakers, the screening, and the establishment of operational procedures are often based on biased information (Dahl et al. 2006). In addition, it has been recognized that methods and criteria for the verification of shale shakers have not been sufficiently qualified and standardized. To address this, a multidisciplinary verification test of various solids-control concepts has been conducted. The objective of the test has been to verify equipment performance in a standardized, onshore test facility related to Oil-mist and vapor emissionVentilation (to obtain a satisfactory working environment)Flow-handling capacity with various drilling fluidsLeakage rate (i.e., the volume of fluid bypassing the filtration screen)Lost-circulation-material featureNoise and vibration levelMaintenance and equipment robustnessFeature for running lost-circulation-material reclamation

The tests were all planned and run in close cooperation with the equipment suppliers to ensure test-objective alignment. Several findings were made throughout the test period that provided vital information for design improvements and increased the industry's competence with respect to solids control.
Impact of Completion Design on Fracture Complexity in Horizontal Shale Wells
Authors: Manchanda Ripudaman , Sharma Mukul M.
Published: June 2014

A proppant-filled fracture induces mechanical stresses in the surrounding rock that cause a reduction in the horizontal-stress contrast and stress reorientation around the open fracture. A 3D geomechanical model is used to simulate the stress reorientation caused by open fractures and to generate horizontal-stress-contrast contour maps. The reduction in horizontal-stress contrast can lead to increased fracture complexity. This paper describes ways to increase fracture complexity by varying the completion design.

In this paper, we identify the impact of operator-controllable variables in a completion design on fracture complexity. This can lead to more-effective completion designs that improve well productivity, reservoir drainage, and, ultimately, the estimated ultimate recovery (EUR).

The possibility of greater fracture complexity and reduced/effective fracture spacing and, thus, a higher drainage area is demonstrated for the alternate fracturing sequence in comparison to the conventional fracturing sequence. The Young's-modulus value of the shale and the in-situ horizontal-stress contrast are shown to be significant factors controlling the extent of fracture complexity generated in a given reservoir. In addition, the effect of proppant mass injected per stage is also shown to significantly impact fracture complexity. We provide optimal ranges of fracture spacing and proppant volume for the various shale formations analyzed. The use of these guidelines should result in more fracture complexity than would otherwise be observed.

The results presented in the paper provide the operator with the knowledge to design completions and fracture treatments (proppant volume, fracture spacing, and sequencing) to maximize reservoir drainage and to increase EURs. This should lead to more-effective completion designs.
Review of California Waterflooding Operations
Authors: Van Wingen N. , Melkonian B.L.
Published: June 2014

This paper presents a statistical review of California waterflooding operations. Water flooding was first started in California in 1944; and, as of June 1, 1960, there were 55 active secondary recovery water-injection projects. In addition, there are 14 projects in which pressure is being maintained by water injection and 18 waste-water-disposal projects.

The number of floods has increased markedly since 1951 when the crude-oil demand began exceeding the supply. However, for varying reasons, 24 water-injection programs have been discontinued.

The majority of floods were started following careful preliminary engineering analyses. No serious difficulties appear to have been encountered as a result of either the relatively high oil viscosity or the rather large average zonal thickness.

No data are available to evaluate increased oil recoveries which may result from the water injection, but response has been described as "good" in 20 of the 55 secondary water floods.

Scope of Investigation

The present investigation is concerned primarily with secondary recovery operations, or those water-injection projects which were instigated at a time when reservoir pressures had declined to values substantially less than the original. Other water-injection projects, those undertaken with the intent of maintaining reservoir pressure relatively near to the original or those primarily instigated for the purpose of waste-water disposal, have not been considered in detail. Projects in these latter classifications are listed in Tables 1 and 2.

Current California Secondary Recovery Projects

As of June 1, 1960, there were 55 active secondary recovery projects in California. At that time, the secondary recovery projects encompassed a total of 322 injection wells, into which water currently is being injected at a rate of 497,895 B/D. Fig. 1 shows the number of active secondary recovery projects in the state by years since the inception of flooding in 1944. This same graph also shows California's total annual crude-oil production and the annual refinery utilization of crude oil. It is interesting to note the accelerated rate at which new projects were started after the crude-oil demand began to exceed the supply. Tables 4a and 4b summarize all available data pertaining to current, active, secondary recovery projects in California.
The Value of Assessing Uncertainty
Authors: McVay Duane A. , Dossary Mubarak N.
Published: June 2014

Despite the perception of lucrative earnings in the petroleum industry, various authors have noted that industry performance is routinely less than expectations. For example, Brashear et al. (2001) noted that the average return was approximately 7% in the 1990s, despite the use of typical project-hurdle rates of at least 15%. The underperformance is generally attributed to poor project evaluation and selection because of chronic bias. Although other authors have investigated cognitive biases in oil-and-gas (O&G) project evaluation, there have been few quantitative studies of the impact of biases on economic performance. We suggest that incomplete investigation and the possible underestimation of the impact of biases in project evaluation and selection are at least partially responsible for the persistence of these biases.

The objectives of our work were to determine quantitatively the value of assessing uncertainty or, alternatively, the cost of underestimating uncertainty. In this paper, we present a new framework for assessing the monetary impact of overconfidence bias and directional bias (i.e., optimism or pessimism) on portfolio performance. For moderate amounts of overconfidence and optimism, expected disappointment (ED) was 30 to 35% of estimated net present value (NPV) for the industry portfolios and optimization cases that we analyzed. Greater degrees of overconfidence and optimism resulted in EDs approaching 100% of estimated NPV. A comparison of modeling results with industry performance in the 1990s indicates that these greater degrees of overconfidence and optimism have been experienced in the industry.

The value of reliably quantifying uncertainty is reducing or eliminating both ED (realizing an NPV is substantially less than estimated NPV) and expected decision error (EDE) (selecting the wrong projects). Because biases are usually related, mitigating one bias will often mitigate others in the process. ED and EDE can be reduced by focusing on the elimination of either overconfidence or optimism, although there is an advantage to focusing on overconfidence. The elimination of ED will improve overall industry performance to the extent that superior projects are available and that better quantification of uncertainty allows the identification of these superior projects.
Four-Fluid-Phase, Fully Implicit Simulation of Surfactant Flooding
Authors: Patacchini Leonardo , de Loubens Romain , Moncorgé Arthur , Trouillaud Adrien
Published: June 2014

The Microemulsion phase behavior model based on oleic/aqueous/surfactant pseudophase equilibrium, commonly used in chemical-flooding simulators, is coupled to Gas/Oil/Water phase equilibrium in our new four-fluid-phase, fully implicit in-house research reservoir simulator (IHRRS) (Moncorgé et al. 2012). The method consists of splitting the equilibrium into two stages, in which all the components other than surfactant are equilibrated first—by use of a black-oil, K-value, or equation of state (EOS) model—and the resulting Gas, Oil, and Water phases are then lumped into pseudophases to be equilibrated by use of the Microemulsion model. This subdivision in stages is conceptual, and at each converged timestep the four phases (Gas, Oil, Water, and Microemulsion, when simultaneously present) will be in equilibrium with each other.

The fluid properties (such as densities, viscosities, and interfacial tensions) and rock/fluid properties (such as relative permeabilities) required in the transport equations are evaluated with models from well-known industrial or academic simulators. Surfactant flooding being usually implemented as a tertiary recovery mechanism, on fields for which complete models that we do not wish to modify already exist, particular care is devoted to ensuring continuity of the physics at the onset of surfactant injection.

Our code is first validated against a reference academic chemical-flooding simulator, on a 1D, three-fluid-phase (Oil/Water/Microemulsion) coreflood. Second, as application examples where it is necessary to account for four phases in equilibrium, we consider a scenario where the chemical flood is preceded by a vaporizing Gas drive, as well as a scenario where dissolved gas is released by the Oil during the flooding process. Some aspects of our implementation, such as numerical dispersion vs. timestep length and nonlinear convergence, are also discussed; in particular, we show that numerical performance is not degraded by the four-phase equilibrium.
Pore Pressure Modelling and Stress-Faulting-Regime Determination of the Montney Shale in the Western Canada Sedimentary Basin
Authors: Contreras Oscar , Hareland Geir , Aguilera Roberto
Published: June 2014

This work establishes an effective approach to predict pore pressure in theoverpressured Montney shale and overburden from sonic logs by implementingnormal-trend and explicit methods. The cause of the overpressure condition inthe Montney is also addressed. These two methods were selected on the basis ofthe study carried out by Contreras et al. (2012) that worked successfully forpore pressure prediction under subpressured conditions in parts of the westernCanada sedimentary basin (WCSB). As a second objective, the stress-faultingregime was determined in the study area by use of stress polygons and data fromdiagnostic fracture-injection-test analysis as a quantification of the minimumhorizontal stress. This is of paramount importance because there is not ageneric theory explaining the stress-faulting regime for most of the westernregion of the WCSB. The Eaton method from sonic logs (Eaton 1975) and theBowers method (Bowers 1995) were implemented in two vertical wells drilledthrough the Montney shale. The first part of the analysis considered two normalcompaction trends, but unreasonable pressure profiles were obtained andrequired a revision on the depositional environment. It was found that for thestudy area, three normal compaction trends have to be considered. The Bowersmethod was initially implemented using both loading and unloading conditions inorder to establish a safe range of pore pressure to allow successful wellplans. It is concluded that undercompaction could be masked as the onlyoverpressure mechanism in the Montney shale in the study area. The formationexperiences an inverse faulting regime that will lead to the creation ofhorizontal hydraulic fractures. The Eaton method using three normal compactiontrends and an exponent equal to 0.9 works successfully in the study area. TheBowers method uses the loading and the unloading conditions, and the specificcorrelation parameters were found to be suitable for the study area and can beextrapolated to adjacent future production and exploratory wells.
Effect of Bank Size on Oil Recovery in the High-Pressure Gas-Driven LPG-Bank Process
Authors: Lacey J.W. , Faris J.E. , Brinkman F.H.
Published: June 2014

This paper presents an analysis of the high-pressure, gas-driven LPG-slug process, based on fluid flow tests in areal models. Two types of tests were made. One series was made in low-pressure models which permitted observation of fluid movement. Three completely miscible analog fluids were used. A second series of tests was made in high-pressure models using methane, propane and a light refined oil saturated with methane at room temperature and 1,550 psig. Under the test conditions of room temperature and a pressure level of 1,550 psig, the phase diagram for the fluids used is similar to those for many of the field systems where the process is considered for use. A method for using these laboratory data to calculate field performance of the process is outlined.

As a result of this work, it is concluded that small banks of LPG (5 per cent HV or less) are not effective in increasing oil recovery in horizontal reservoirs. Instead, where small banks are used, the driving gas quickly penetrates the LPG bank because of fingering and channeling; and from this point on, the process behaves essentially as an immiscible gas-injection project. The validity of this conclusion was substantiated by:laboratory studies of the effect of rate, model size and mobility ratio on miscible displacement in areal models; andcalculation of field recovery, which compared closely with actual field recovery.

Introduction

Field applications and pilot tests of the gas-driven, LPG-bank, oil-recovery process are on the increase. Most of these tests are employing small banks (2 to 5 per cent hydrocarbon volume) of LPG, which is miscible with both the driving gas and the oil in place, in an effort to attain an effective yet economical miscible displacement of oil by gas. The expectation of miscible displacement with small banks is based on the concepts that:lengths of solvent-oil mixed zones, measured during miscible displacements in long slim cores, are representative of those that will occur in the field; andareal sweep efficiencies measured in electrolytic model studies are applicable to miscible displacement in reservoirs.
Long-Term Economic Viability of Production From Unconventional Liquids-Rich Reservoirs: The Case of Bakken Field
Authors: Ozkan Sarp , Kurtoglu Basak , Ozkan Erdal
Published: June 2014

Long-term economic viability of unconventional reservoirs is evaluated from the profit-maximizing perspective of a producing company. The case of the liquids-rich production from the Bakken field is considered as a representative of unconventional resources. A profit-margin optimization model is constructed for a company to meet the demand it faces from a stock of conventional and unconventional resources given different sets of exogenously determined prices. The model is parameterized using the different production-decline rates of the two sources, physical and economic exhaustibility of the resources, and the ever-increasing marginal cost of adding conventional resources into the company portfolio. The optimal extraction path of oil from the conventional and unconventional reservoirs is assessed, and the long-term economic consequence of keeping the unconventional resource in the ground for different oil-price scenarios is predicted. The model reveals the appropriate composition of a portfolio of conventional and unconventional resources. In the case of a high-price scenario, the optimal efficient extraction path is the pursuit of additional conventional resources before using unconventionals to meet the demand. For the reference-price scenario, the decline of the conventional reserves should be substituted with unconventionals from the beginning. The profitability of the enhanced oil recovery (EOR) applications in unconventional reservoirs and when they should be implemented are also determined. Contrary to common expectation, it is shown that the EOR technology is more justifiable in the case of a lower price forecast.
Effects of Gravity, Foaminess, and Pressure Drawdown on Primary-Depletion Recovery Factor in Heavy-Oil Systems
Authors: Alshmakhy Ahmed , Maini Brij B.
Published: June 2014

The unusually high primary recovery factors (RFs) observed in numerous heavy-oil reservoirs are often attributed to foamy oil flow (i.e., the non-Darcy flow involving formation and flow of gas-in-oil dispersion). It occurs when the wells are produced aggressively at high drawdown pressures that led to conditions in which the viscous forces become sufficiently strong to overcome the capillary forces in pushing dispersed bubbles through pore throats. The role of gravitational forces in generating such dispersed flow has not been studied adequately. This work was intended to evaluate the contribution of gravitational forces in primary depletion of heavy-oil formations under foamy flow conditions.

Primary-depletion tests were conducted in a 200-cm-long sandpack that was held in either horizontal or vertical orientation. The results of horizontal depletion tests were compared with the depletion tests conducted with the sandpack in the vertical direction. Vertical depletions showed better recoveries at slower depletion rates compared with horizontal depletions.

The RFs of both horizontal and vertical depletions were correlated against the average drawdown pressure available to move the oil. It was found that the RF shows a strong dependence on the average drawdown pressure. It was also found that the curve of RF vs. average drawdown pressure moves slightly toward higher recoveries in the presence of an added foaming agent (i.e., with increased oil foaminess).
Method for Consistent Valuation of Assets With Multiple Sources of Uncertainty
Authors: Wilkinson David , Bailey William J. , Cou?t Benoît
Published: June 2014

A simplified version of the Smith and Nau (1995) integrated solution scheme is applied to the valuation of an oilfield project possessing salvage options and both private and public uncertainties. It is shown that the computed valuation is consistent with the definition of the real option price as the maximum value that could be obtained, without market risk, from an ensemble of projects that sample the private uncertainty. The attainment of this value requires an optimal decision strategy and a hedging strategy, both of which are obtained as a byproduct of the valuation. The interpretation of the obtained value is validated by forward simulation over an ensemble of projects, by use of a fully reproducible worked example.
Industry Analogies for Successful Implementation of Drilling-Systems Automation and Real-Time Operating Centers
Authors: de Wardt John P.
Published: June 2014

Industry analogies provide excellent insight to finding the optimal balance among manual, automatic, and remote operations. They also can provide excellent insight into data displays and decision making.

It is very important to define the current state and the future desired state for data acquisition, processing, decision making, and workflow in high-performance drilling operations. Understanding the difference between these two states provides the opportunity to guide the successful implementation of drilling-systems automation (DSA) and real-time operations centers (RTOCs). Aviation and space flight have been offered as appropriate analogies for the future application of drilling-systems automation. Formula 1® motor racing offers a highly competitive analogy for managing data flows combined with control systems.

Various industry analogies are reviewed for their applicability to DSA and RTOCs. The benefits and drawbacks of each are highlighted. An assessment uses insights from other analogous industries to provide the opportunity to define best practices and relevant application for various well types from these analogies.

An advanced application of DSA and RTOCs will change the role of the driller as well as the competency makeup and location of the drilling team. Maximal benefit from DSA and RTOCs can be achieved through carefully planned implementation on the basis of relevant learning from other industries.
Zonal Isolation through Gas Hydrates Offshore Tanzania
Authors: Vølstad J. , Tveit T. , Aguilar P. , Hurtado N. , Bogaerts M.
Published: June 2014

Deepwater cementing becomes increasingly challenging as drilling operations move to greater water depths and to more remote locations. Understanding these challenges and mitigating the associated risks in time has become very important tasks. Before the first exploration well for an operator offshore Tanzania was spudded in a water depth of 2580 m, an extensive analysis was performed to determine all the risks associated with cementing operations, especially in the increasingly challenging and critical surface casing section.

The risks determined were low temperatures at seabed, unconsolidated formations close to seabed, potential shallow gas, and likely presence of hydrates. Because of the remoteness and limited oilfield infrastructure, logistics were also determined to be demanding. To successfully continue to drill further sections, the job objectives were zonal isolation across the shallow flow and hydrate zones, cementing back to seabed to provide a stable wellhead, and good cement around the casing shoe providing isolation for deeper formations.

The cement job was designed to meet these challenges and objectives. Optimized particle-size distribution (PSD) cement slurry with low density was designed to avoid losses and still develop high compressive strength quickly at low temperatures. Low-temperature gas-migration additive and cement set enhancer were included to provide a short transition time preventing gas migration to seabed. Because of the lower cement ratio in the optimized PSD-blend, the slurry did not destabilize the hydrates during the setting process. The cement placement was simulated to confirm the job design would meet its objectives.

Careful preparation and the optimized PSD-sluny system allowed executing the job meeting all objectives. Good zonal isolation and a successful leak off test were achieved, eliminating the contingency liner.
Real-Time Evaluation of Hole-Cleaning Conditions With a Transient Cuttings-Transport Model
Authors: Cayeux E.. , Mesagan T.. , Tanripada S.. , Zidan M.. , Fjelde K.K.. K.
Published: June 2014

During a drilling operation, a real-time analysis of surface and downhole measurements can give indications of poor hole cleaning. However, it is not always intuitive to understand how and where the cuttings are settling in the borehole because the transportation of cuttings and the formation of cuttings beds are largely influenced by the series of actions performed during the operation. With a transient cuttings-transport model, it is possible to get a continuously updated prognosis of the distribution of cuttings in suspension and in beds along the annulus. This information can be of prime importance for making decisions to deal with and prevent poor hole-cleaning conditions.

A transient cuttings-transport model has been obtained by integrating closure laws for cuttings transport into a transient drilling model that accounts for both fluid transport and drillstring mechanics.

This paper presents how this model was used to monitor two different drilling operations in the North Sea: one using conventional drilling and one using managed-pressure drilling (MPD). Some unknown parameters within the model (e.g., the size of the cuttings particles) were calibrated to obtain a better match with the top-side measurements (cuttings-flow rate, active pit reduction as a result of cuttings removal). With the calibrated model, the prediction of cuttings-bed locations was confirmed by actual drilling incidents such as packoffs and overpulls while tripping out of hole.

On the basis of the calibrated transient cuttings-transport model, it is thereby possible to evaluate the adjustments of the drilling parameters that are necessary to stop and possibly remove the cuttings beds, thus giving the drilling team the opportunity to take remedial and preventive actions on the basis of quantitative evaluations, rather than solely on the intuition and experience of the decision makers.