bluuebunny/crossref_metadata_2025 huggingface dataset:
Transport Properties of Hydrate Bearing Formations from Pore-Scale Modeling
Authors: Phirani J. , Pitchumani R. , Mohanty K. K.
Published: October 2009

Gas hydrates are an attractive source of energy as natural gas can be produced from these deposits by depressurization or thermal stimulation. Empirical correlations developed in hydrology and petroleum engineering have been used for describing transport properties of sediments containing gas hydrates in hydrate simulators. The goal of this work is to estimate the transport properties of hydrate-bearing sediments from pore-scale modeling. Sediment particles have been packed using a discrete element method and pore radius distribution is calculated using Delaunay triangulation. Hydrate deposition is modeled in a single pore to develop pore-scale laws of hydrate occupancy. Pore radius distributions are recalculated after hydrate deposition. Percolation theory is used to numerically calculate effective transport properties of the medium at different saturations. Pore-scale models showed that the hydrates form at the pore walls if deposited from the flow of methane-saturated water alone. The saturation of hydrate deposited in different size pores was found to be uniform. A Gaussian distribution of particle size of the sediment results in a Rayleigh distribution of pore throat radius. As the variance of the particle size increases, so does the width of the pore size distribution. As the hydrate saturation increases, the permeability of the sediment decreases. This decrease follows Civan's correlation with a β of 0.75. The relative permeability becomes increasingly dependent on water saturation as the hydrate saturation in the sediment increases. A new correlation for relative permeability is developed by matching the percolation theory estimates.
Numerical Modeling of Multi-Stranded Hydraulic Fracture Propagation: Accounting for the Interaction Between Induced and Natural Fractures
Authors: Dahi-Taleghani Arash , Olson Jon E.
Published: October 2009

Recent examples of hydraulic fracture diagnostic data suggest complex, multi-stranded hydraulic fractures geometry is a common occurrence. This reality is in stark contrast to the industry-standard design models based on the assumption of symmetric, planar, bi-wing geometry. The interaction between pre-existing natural fractures and the advancing hydraulic fracture is a key condition leading to complex fracture patterns. Performing hydraulic fracture design calculations under these less than ideal conditions requires modeling fracture intersections and tracking fluid fronts in the network of reactivated fissures. Whether a hydraulic fracture crosses or is arrested by a pre-existing natural fracture is controlled by shear strength and potential slippage at the fracture intersections, as well as potential debonding of sealed cracks in the near-tip region of a propagating hydraulic fracture. We present a complex hydraulic fracture pattern propagation model based on the Extended Finite Element Method (XFEM) as a design tool that can be used to optimize treatment parameters under complex propagation conditions. Results demonstrate that fracture pattern complexity is strongly controlled by the magnitude of anisotropy of in situ stresses, rock toughness, and natural fracture cement strength as well as the orientation of the natural fractures relative to the hydraulic fracture. Analysis shows that the growing hydraulic fracture may exert enough tensile and shear stresses on cemented natural fractures that they may be debonded, opened and/or sheared in advance of hydraulic fracture tip arrival, while under other conditions, natural fractures will be unaffected by the hydraulic fracture. Detailed aperture distributions at the intersection between fracture segments shows the potential for difficulty in proppant transport under complex fracture propagation conditions.
The Impact of Oil Prices on Oil Shale Development in the United States
Authors: Biglarbigi Khosrow , Killen James , Carolus Marshall
Published: October 2009

The United States has the largest oil shale resources in the world, in excess of 6 trillion barrels. Potential U.S. oil shale reserves could exceed 800 billion barrels, depending on oil price. New technologies may soon enable these resources to be produced efficiently and economically. Recently, increased oil demand, tightening supplies, and higher oil prices stimulated investment in energy projects around the globe, driving up the cost of materials, skilled labor, and other project inputs. A clear example can be seen in the rapid increase of capital and operating costs in Alberta's oil sands. Similar experiences could be expected during the development of a domestic oil shale industry. This raises questions about the effect of oil price on oil shale economics, including both capital and operating costs.

To answer this question, an analysis was conducted using the oil price as a surrogate for energy costs, tightness of the labor market, the costs of materials, and other factors which impact the development of oil shale projects. After developing a relationship between the oil price and the cost of development, an analysis was conducted to determine the impact caused by increasing oil prices on the minimum economic price of four representative oil shale development technologies.

This paper will discuss the relationship and impact of oil price and oil shale development costs. In addition, the paper will describe the impact of the cost relationship on production and other macro-economic benefits which can be realized.
Corrosion Inhibition of New 15 Chromium Tubulars in Acid Stimulation Fluids at High Temperatures
Authors: Boles Joel , Ke Mingjie , Parker Carson
Published: October 2009

Over the past several years, a substantial increase in deep water exploration and production has brought new challenges to corrosion and material technology. The production environments in deep wells normally involve high temperature, high pressure, and sweet/sour gas. These severe conditions require corrosion resistant alloy (CRA) for well completions and production. To meet industry demands, one manufacturer has recently developed a new 15 chromium (15Cr) steel tubular as a high strength tubular (125 ksi) to control CO2 corrosion. With its modified metal composition, the new 15Cr further improves the corrosion resistance of some of chemically enhanced 13Cr, and can be applicable at temperatures up to 392°F where the use of 22Cr duplex would otherwise be required. In other words, if not for this new 15Cr, they would have to use the 22Cr, which is more expensive. With the introduction of new 15Cr to oil and gas well operations, it becomes necessary to evaluate its corrosion behavior in acid stimulation fluids at high temperatures. Due to the corrosive nature of acids, understanding its corrosion behavior and optimizing effective acid corrosion inhibitors/inhibitor packages for 15Cr tubular are critical to maximize the life of tubulars and further improve overall well completion effectiveness.

This paper presents results of acid corrosion tests performed on new 15Cr tubular samples at temperatures from 260 to 350°F. The acids tested included hydrochloric acid, hydrochloric-hydrofluoric acid (mud acid), acetic acid, formic acid and their combinations. Several acid corrosion inhibitors/inhibitor packages normally used for 13Cr were evaluated to determine their effectiveness on new 15Cr. Results indicated that corrosion behavior of 15Cr in acids can be completely different from that of conventional API 13Cr. It appears that the chemical compositions of 15Cr and heat treatments during the process of steel manufacturing play a significant role in corrosion behavior. Also, the data shows that some inhibitor packages typically used for 13Cr do not provide adequate corrosion protection on 15Cr materials. Furthermore, practical guidelines for the use of acid corrosion inhibitors/inhibitor packages with 15Cr CRA metallurgy are discussed.
A Study of Heat Related Factors Caused by Color Selection of Hard Hats and FRC Garments in Out Door Work Environments
Authors: Davis Michael , Kaminski Don , Oliver Michael Chase , Graf Jake , Pilling Lee
Published: October 2009

The purpose of the study was to validate comments from the field employees describing increased heat stress and discomfort wearing the dark hard hats and dark coveralls during the hot sunny weather during the summers.

The purpose of this study is to determine the following: What criteria should be used to evaluate any potential heat stress created by the color of the fabric or hard hats?Does the color of the fabric or hard hat affect the potential heat stress on a worker in the sun?If there is a difference, which color would contribute least to potential heat stress?Would the data clearly suggest which color to select?

With these goals in mind, a testing protocol was developed to determine if the color would affect the perceived comfort and apparent heat stress of the user in hot sunny conditions.

The color of hardhat and garment does make a significant difference in the surface temperature that would affect conduction and radiation as a method to cool the body. The differential in surface temperature is significant between the dark and light colors as expected. Surface temperature differentials ranged up to 49° F on the hard hat and 45° F on the garment. The dark colors add heat load to the body, therefore color does make a significant difference in the ability to radiate heat as a method of cooling the body.

Dark colors absorb more energy and therefore have a higher surface temperature limiting the bodies' ability to radiate heat that is either absorbed from the sun or created by activity. The study indicates the selection of the hard hat and garment colors significantly contribute to the bodies' ability to dissipate heat. Further study will determine the physiological impact to the bodies' ability to regulate its core temperature.
Evaluating Horizontal Well Placement and Hydraulic Fracture Spacing/Conductivity in the Bakken Formation, North Dakota
Authors: Lolon E. P. , Cipolla C. L. , Weijers L. , Hesketh R. E. , Grigg M. W.
Published: October 2009

The success of horizontal well completions in the Bakken formation has increasingly attracted much interest within the oil and gas industry. Improved stimulation techniques including the use of new fluids and proppants, better zonal coverage through improved diversion and staging, and/or re-fracture treatments contributed to this success. This paper presents the results of a fracture modeling and multi-well simulation study to evaluate down-spacing potential for horizontal wells. This study also examines how the number of stages along the lateral, proppant type, treatment volume, fracture conductivity, and effective oil permeability affect production profiles and oil recovery in the middle Bakken formation, North Dakota.

In this work, a lumped 3D fracture growth model was calibrated with direct fracture mapping observations that showed significant upward height growth into the Lodgepole formation. The horizontal well orientation is selected to promote transverse fractures. This paper provides details about the fracture treatment designs and subsequent integration of the fracture geometry and conductivity descriptions into the reservoir model. Various fracture treatment designs are evaluated, with the goal of optimizing fracture conductivity and minimizing upward height growth (which can be a problem in the middle Bakken).

The results of this study showed a significant infill drilling potential because of the low estimated effective oil permeability (0.002-0.04 mD). Reducing the horizontal well spacing from one to two or three wells per 640 acres should significantly increase oil recovery. The optimum number of fracture treatment stages along the horizontal lateral depends largely on reservoir permeability, lateral length, and number of wells per section.
CO2 Sequestration: Temperature and Gas Compositional Effects on the Kinetics of Mineralogical Reactions
Authors: Mandalaparty Prashanth , Deo Milind , Moore Joseph
Published: October 2009

It may be possible to lower costs of Carbon Capture and Sequestration by keeping constituents such as sulfur dioxide (SO2) in the flue gas stream. The reactive behavior of pure CO2 and CO2 + SO2 mixtures within a geologically realistic environment was examined. The experimental apparatus consisted of a series of four high-pressure reactors operated at different conditions and with different feed gas compositions to observe changes in both the rock and water compositions. The rock consisted of equal proportions of quartz, calcite, andesine, dolomite, chlorite and magnesite (constituents in arkose or dirty sand stone). The brine was prepared from laboratory grade sodium chloride and by varying the amount of magnesium concentration in the brine. Several long-term batch experiments with pure CO2 were carried out at different temperatures. Each mineral in the mixture showed evidence of participating in the geo-chemical reactions. Layers of calcite were seen growing on the surface of the arkose. Analcime deposits were omnipresent, either occurring as large connected aggregates or as deposits on the surfaces of other minerals (Quartz). Ankerite and calcite depositions were observed as amorphous masses intergrown with the feed. The CO2 + SO2 mixture experiments showed growth of euhedral anhydrite crystals and pronounced dissolution patterns over the examined surfaces. The growth of these new phases would lead to significant changes in the petrophysical properties of the rock. The trends in ionic concentration changes in the aqueous phase complemented the changes in the rock chemistry. The rates of these reactions were computed by measuring the changes in the compositions of the initial and the final samples. The rates of these reactions were computed by computing the changes in the compositions of the initial and the final rock samples (both individual and mixture) provided by the XRD analyses and were observed to be lower than expected.
Optimizing Mature Gas Wells in South Texas—A Team Approach
Authors: Harms Larry , Urlaub John , Carrier Bruce , Cremar Billy
Published: October 2009

A multi-discipline team was commissioned to bring the right technology and resources to bear to optimize production in a pilot area (67 mature gas wells) in the Lobo field in South Texas. The team used a more aggressive approach towards artificial lift, minimizing pressure and monitoring well performance. The team's work resulted in a 10% production increase with essentially no decline and 3.2 BCF incremental gas over a 2.5 year period. Details of what was done including increased focus on the natural work team, production monitoring, data collection, well automation, debottlenecking, additional plunger lift installations, siphon strings, foamer use, wellhead compression, lowering field pressure and reducing pressure variability are presented. Overall costs and production results are shown along with results from representative wells.
Intelligent Well Systems—Providing Value or Just Another Completion?
Authors: Sun Kai , Constantine Jesse , Tirado Ricardo , Eriksen Frank , Costa Luiz
Published: October 2009

This work reviews several typical intelligent well systems (IWS) completed, including a gas producer, oil producer, auto-gas lift oil producer, multilateral IWS producer, and horizontal openhole multi-isolation producer. For each case, the wellbore modeling, completion design, choking operation strategies, and estimated performance will be introduced.

Case histories based on the analysis of the well modeling results at the design stage of the IWS completion, including well performance along with real-time data, will demonstrate:

Was value realized by using an IWS? How did the IWS completion, downhole choking, and monitoring contribute to adding value in accelerating hydrocarbon production, managing production allocations, delaying or minimizing water production, increasing recovery, and decreasing CAPEX or intervention costs?

In conclusion, this paper will show how modeling technologies were developed to derive the IWS well and equipment design such as tool selection, customized choking positions, erosion protection, and tubing movement estimation. It will cover lessons learned through our experience in intelligent well systems, including flow modeling, erosion analysis, tool selection, and crossover control, and how we expect the future movement of this technology. to evolve.
A New Approach to Compositional Modeling of CO2 Injection in Fractured Media Compared to Experimental Data
Authors: Moortgat Joachim , Firoozabadi Abbas , Farshi Mohammad Moravvej
Published: October 2009

In a recent PhD dissertation (Darvish 2007), data and modeling are presented from an experiment in which CO2 is injected in a tall vertical core, surrounded by fractures. After injecting CO2 for 22 days, 65% of the oil in place is recovered (and still increasing). However, the modeling with a commercial simulator results in only 12% recovery, despite adjusting parameters. We will discuss inherent flaws in current simulators that impede realistic simulation of CO2 injection in fractured media, even at laboratory scales. These issues include: problems in accounting for phase behavior effects and Fickian diffusion in dualporosity models, and excessive numerical diffusion in all simulators that use the finite difference methods. To improve on these weaknesses, we use a higher-order algorithm based on the combined discontinuous Galerkin, mixed hybrid finite element and discrete fracture techniques. We extend that model here to include a self-consistent model for Fickian diffusion, and time splitting in an improved-implicit-pressure-explicit-composition (IIMPEC) scheme. With this new approach, we can reproduce all experimental results in Darvish (2007). The results further confirm the prospects of CO2 injection for enhanced oil recovery in fractured reservoirs.
Measuring Hydraulic Fracture Growth in Naturally Fractured Rock
Authors: Jeffrey R. G. , Bunger A. P. , Lecampion B. , Zhang X. , Chen Z. R. , van As A. , Allison D. P. , de Beer W. , Dudley J. W. , Siebrits E. , Thiercelin M. , Mainguy M.
Published: October 2009

A field experiment was carried out to measure hydraulic fracture growth in naturally fractured rock. Hydraulic fracture interactions with pre-existing natural fractures, shear zones, veins, and adjacent hydraulic fractures were measured and mapped during the project. Tiltmeter and microseismic arrays were installed to test the performance of these monitoring methods in determining the fracture geometry, which was eventually revealed by the mine-through mapping. The physically mapped fractures were oriented approximately horizontally, perpendicular to the minimum stress direction. They crossed natural fractures and shear zones, but were offset by some shear zones, most often oriented with an approximate 45° dip. The analysis of the tiltmeter data correctly predicted fractures to be horizontal. Microseismic monitoring, although a proven method for imaging hydraulic fractures, did not resolve the fracture orientation or size for conditions at the E48 Northparkes site because of a lack of recorded micro-seismic events. The hydraulic fractures grew through solid rock, along natural fractures and stepped along inclined shear zones. Proppant was distributed throughout the fractures, including in the offset portions. Initial modeling indicates higher treatment pressure and slower extension rate for a stepped 2D hydraulic fracture compared to a straight fracture.
Real Time Diagnostics of Gas Lift Systems Using Intelligent Agents: A Case Study
Authors: Stephenson G. , Molotkov R. , De Guzman N. , Lafferty L.
Published: October 2009

This paper describes a new method to continuously monitor and diagnose the condition of wells producing via continuous gas lift. The paper describes the application of this system in a mature onshore gas lift field in the Western United States and the results obtained therein. A central problem related to the operation of gas lift wells is the ability to identify underperforming wells and to address the underlying issues appropriately and in a timely manner. This problem is compounded by the trend toward leaner operations and relative scarcity of application specific domain knowledge. The purpose of this method is to address these issues by leveraging real time data, gas lift domain expertise and proven steady state analysis techniques in a desktop software application.

This system performs four key functions: monitoring the wells’ condition by collecting data; assessing the meaning of this data; recommending actions for correcting problems and responding to threats; and explaining their recommendations.

The performance of the system has met initial expectations and provided additional unforeseen benefits. This paper sites specific cases which compare agent predictions to expert diagnoses and quantify the benefits of taking the recommended actions. What was found was that while the correct diagnoses of well performance issues was beneficial, the real benefit was in allowing production engineers to analyze a greater number of wells in far less time. To that end, the paper will discuss the role of this system as it relates to the overall production management workflow.

The success of this project has demonstrated that intelligent agents can be used to effectively perform functions which were historically performed by a handful of experts. The paper will discuss key system design features which enable this level of functionality as well as other potential areas where the technology can be extended in the future.
Mechanistic Modeling of Emulsion Formation and Heat Transfer During the Steam-Assisted Gravity Drainage (SAGD) Process
Authors: Azom Prince N. , Srinivasan Sanjay
Published: October 2009

Even in the absence of flow barriers and other reservoir heterogeneities, current SAGD models underestimate heavy oil recovery, and are generally seen to be inaccurate in predicting important production characteristics like steam oil ratio (SOR) and water oil ratio (WOR), when compared against experimental or field data. It has been hypothesized by some researchers that water-in-oil emulsions are formed at the steam-oil interface. It is our premise that transport of these emulsion droplets into the bitumen phase facilitates convective heat transfer resulting in improved recovery. Incorporating these effects is key to accurately modeling the SAGD process.

Unfortunately, the physics of emulsion formation and transport in porous media is not well understood, and current simulators do not have the capability to directly model such effects. A new approach that models the emulsion droplets as chemical species and accounts for the dispersion and adsorption phenomena is implemented in this paper. This model utilizes the features available in most commercial simulators in order to model emulsion generation, propagation and coalescence in porous media. The results from such a mechanistic simulation are compared against published SAGD experimental data. Our results show significant improvement from previous SAGD models and bolster the argument that emulsions are responsible for a key heat transport mechanism during SAGD. The simulation is also being used currently to design laboratory experiments to verify the formation of emulsions and their net effect on heat transfer.
High Resolution, Real-Time Casing Strain Imaging for Reservoir and Well Integrity Monitoring: Demonstration of Monitoring Capability in a Field Installation
Authors: Pearce J. G. , Rambow F. H. K. , Shroyer W. , Huckabee P. , de Jongh H. , Dria D. E. , Childers B. A. , Hall T. S. , Dominique T.
Published: October 2009

Casing deformation can be used as a direct indicator or measurement of reservoir geomechanical strain, such as may occur with

Vertical compaction accompanying pressure depletion of high-compressibility hydrocarbon reservoirs; Vertical strain dilation due to stress arching; Shear events associated with fault movement and reservoir bed boundary movement during subsidence; Localized strain events such as pipe ovalization due to highly anisotropic loading or formation strain anisotropy; and Pressure changes due to depletion of or injection into reservoirs.

Identifying and quantifying these events early can help an operator remedy a potentially damaging production scenario, apply the correct seismic transit time correction during time-lapse reservoir seismic monitoring, or monitor production, injection, and pass-through zones for pressure depletion effects.

We have installed, in an industry first, a high-resolution fiber-optic strain imaging system in a producing well. The theoretical, experimental and early deployment test trial details of this technology were reported in SPE 109941, presented at the 2007 SPE ATCE. In this paper, we will report high-resolution strain monitoring results obtained on a set of casing joints which were instrumented with several thousand fiber-optic strain sensors, deployed as a single fiber cable in an onshore production well, installed using normal rig equipment. Of particular interest at this early stage in the well's life is the demonstration of the strain measurement resolution and sensitivity, as evidenced by our ability to monitor the differential pressure between the inside and outside of the casing while circulating prior to cementing, during the cementing operation and while the cement was curing. This monitoring yielded excellent results while cementing the instrumented intermediate casing string, as well as while cementing the production casing string. Cemented at a measured depth of 8000 feet in an unconventional gas well, the strain-instrumented casing joints in conjunction with a distributed temperature sensor and external pressure gauge have continued to provide strain, temperature and behind-casing pressure readings through the remainder of the well construction, completion, hydraulic fracturing and the current, early production operations some six months after initial installation.
Expandable Tubulars Enable Multi-Zone Frac-Packing in the Open Hole
Authors: York Patrick , Gandikota Raju
Published: October 2009

Investigation is underway to enhance potential production rates by actualizing a method of frac-packing multi-zone slim holes and sidetracks using solid and slotted expandable casing. This innovative technique replaces the production liner and the cementing and perforating phases in a normal completion. The increased completion ID and flow areas provided by the expandable completion allow a significant increase in the frac-pack sand-screen size and associated production tubulars. The expanded completion liner itself offers more than a ten-fold increase in inflow area over a conventional perforated liner. These two factors, when combined, allow both reliable and improved production rates from 6 in. openhole sidetracked sand control wells requiring frac-packing.

By utilizing these expandable slotted completion liners in conjunction with a newly developed solid expandable openhole packer system, the operator can selectively expand discrete production (or injection) zones and, with an appropriate frac-pack screen design, effectively control flow from the individual zones. Using selectively-expandable isolation devices allows the end user to decide their placement after the well evaluation data has been analyzed. This flexibility enables the end user to optimize the effectiveness of the completion.

This paper will review the completion challenges with perforating and frac-packing inside small completion liners or open holes, the available technologies to perform isolation in the open hole, and the process and features associated with an expandable completion run prior to frac-packing. The results of ongoing testing and field trials of the expandable packer system will be presented and analyzed along with supporting modeling and simulation work.

In effect, the new system allows an operator to perform an open-hole frac-pack inside a 6 in. sidetracked hole, obtain higher sustained production rates, and thereby, improve project economics over conventional techniques. This system, in some cases, will allow additional reserves recovery in difficult sand-control environments and revitalize maturing fields.
History Matching by Simultaneous Calibration of Reservoir Geological Models at Pore-Level and Field Scales
Authors: Barrera Alvaro , Srinivasan Sanjay
Published: October 2009

Reliable predictions of reservoir flow response require a realistic geological model of heterogeneity and an understanding of its relationship to flow performance of the reservoir. This paper presents a novel approach for integrating dynamic data in reservoir models that utilizes the probability perturbation approach for the simultaneous calibration of geological models at field scale and multiphase flow functions associated with pore-level spatial representations of the porous media.

In this probabilistic approach, a stochastic simulator is used to model the spatial distribution of a discrete number of rock types identified by rock/connectivity indexes (CIs). Each CI corresponds to a particular pore network structure with a characteristic connectivity. Primary drainage and imbibition displacements are modeled on the 3D pore networks to generate multiphase flow functions, including effective permeability and porosity of the rock, the relative permeabilities and capillary pressure, linked to the CIs. During the assisted history matching, the stochastic simulator perturbs the spatial distribution of the CIs to match the simulated pressures and flow rates to historic data. Perturbation of the CIs in turn results in the update of all the flow functions.

The results from the integrated history matching procedure are presented for a realistic field example. The convergence rate of the proposed method is comparable to other current techniques with the distinction of enabling consistent updates to all the flow functions while at the same time honoring the geological/sedimentary model for the distribution of petrophysical properties. Consequently, the reservoir model and its predictions are consistent with realistic geological processes and the response obtained for the reference model.
Pore-Level Mechanics of Forced and Spontaneous Imbibition of Aqueous Surfactant Solutions in Fractured Porous Media
Authors: Alshehri Amar J. , Sagatov Ernar , Kovscek Anthony R.
Published: October 2009

Water flooding typically recovers about 50% of the original oil in place leaving much oil in the reservoir. Recovery efficiency in fractured reservoirs can be dramatically lower in comparison to conventional reservoirs because water channels selectively from injector to producer leaving considerable oil within the matrix and uncontacted by injected water. An enhanced recovery process is needed to access such oil held in the reservoir matrix. Addition of aqueous surfactants to injection water dramatically reduces oil/water interfacial tension and surfactant may adsorb to oil-wet rock surfaces inducing a shift in wettability that improves the imbibition of water. At the pore level, capillary forces are responsible for oil trapping and generally dominate over viscous and gravitational forces. Because of the reduction in interfacial tension between oil and water with the addition of surfactant, the role of capillary forces on fluid flow can be minimized. When gravity parameters are large enough to give a Bond number (ratio of gravity to capillary forces) greater than 10, gravitational forces become more dominant and oil held with rock matrix by capillarity may be released as a result of buoyancy. In this work, we use experiments conducted in two-dimensional micromodels to investigate the effect of gravity at low interfacial tension. The micromodels have the geometrical and topological characteristics of sandstone and the network is etched into silicon. Porelevel mechanics are observed directly via a reflected-light microscope. A screening study of sulfonate and sulfate surfactants was conducted to choose an appropriate system compatible with the light crude oil (27°API). A variety of flow behavior through the microscope is investigated including forced and spontaneous imbibition. Results are illustrated via pore-level photo and image analysis of microscopic pictures of the micromodel. Forced displacements are conducted at realistic flow rates to maintain a 1 m/day Darcy velocity and at surfactant concentrations of 0.9% to 1.25%. Forced displacement with a horizontal or vertical positioning of the micromodel yields dramatic improvement of recovery for surfactant injection cases. Most of the oil retained after a waterflood was recovered by tertiary injection of surfactant solution. In comparison, about 25% oil saturation remained after a waterflood.
Methodology to Compare Smart and Conventional Wells
Authors: Schiozer Denis J. , da Silva Joäo Paulo Q. G.
Published: October 2009

Smart wells are being used recently to add operational flexibility to petroleum production. Considering offshore fields with water injection, smart wells can be very useful to control water production and to improve oil production. The advantages of smart wells are that they have devices like valves and sensors are able to monitor and control production, in real time, adding flexibility to the operation.

However, the effect of smart wells on the net present value (NPV) of the project has to be carefully quantified because of the additional investments. The expected gain is a function of several parameters, especially operational controls and economic parameters. Therefore, a fair comparison between these two wells requires a methodology of production strategy optimization especially designed to capture the details in the performance of these wells. The differences are even more complicated to be quantified in the presence of uncertainties.

Therefore, the objective of this work is to present an example with a comparison between smart and conventional wells, considering uncertainties in the geological and economic models.

A methodology of production strategy optimization, presented in a previous work (Silva and Schiozer, 2009), considering the availability of different production capacities, is used in this work. The main parameters altered are: position and number of wells, water cut and schedule of well's drilling.

The results showed small differences between the two alternatives. Smart wells were able to improve oil production and reduce water production but, in most cases, the NPV indicated that the use of conventional wells was slightly more advantageous. Also, the operational conditions, such as platform capacities, have a high impact on the results. The results are also very dependent on the economic model and additional investments required to use smart wells.
Assisted History Matching in an Offshore Turbidite Reservoir with Active Reservoir Management
Authors: Rey Alvaro , Ballin Paulo , Chick Vitalis , Park Jeff , Kim Jong-UK , Datta-Gupta Akhil
Published: October 2009

Streamline-based assisted and automatic history matching techniques have shown great potential in reconciling high resolution geologic models to production data. Several field applications have demonstrated the efficiency of streamline-based sensitivity calculations together with the generalized travel time inversion (GTTI) for history matching. However, a limitation of the current GTTI based production data misfit calculations is that it is best suited for continuous and monotonic production histories. Field applications very often include active reservoir management decisions that involve well shut-in, recompletions and pattern conversions. These introduce significant discontinuities and non-monotonic effects in the production response.

In this paper we propose an efficient and novel technique that handles production discontinuities through a transformation of the production data and by eliminating high frequency details in the transformed domain. The technique also reduces nonmonotonic behavior and results in a response more suitable for the GTTI based misfit calculations. Our proposed approach has been applied to an offshore turbidite reservoir with active reservoir management and highly detailed production information. The static model contains more than three-hundred-thousand cells, complex sand depositional distribution combined with fault structures, four pairs of injector, deviated producing wells and more than 8 years of production history. Previous history matching attempts using traditional approaches had difficulties matching production response at the individual well level. With our proposed modification to the GTTI approach, a significant improvement on the well match quality was obtained. Most importantly, by visualizing the streamlines and the dynamic adjustment of flow paths during history matching, we could easily identify the areas of inconsistency between the geologic model and the production data. The calibrated geologic model suggests communication within sand channels, differences in flow paths and barriers that have not been included in the previous geologic and seismic interpretation.
The Importance of Asphaltene Deposition Measurements in the Design and Operation of Subsea Pipelines
Authors: Akbarzadeh Kamran , Ratulowski John , Lindvig Thomas , Davies Tara , Huo Zhongxin , Broze George , Howe Richard , Lagers Kees
Published: October 2009

Shell Exploration & Production Company has been operating fields producing asphaltenic fluids in the Gulf of Mexico (GOM) for several years and had previously been unable to accurately predict the extent and location of asphaltene deposition. As a result, well bores and subsea flowlines have in some cases been plugged whereas in other cases it is likely that inhibitor injections have been unnecessarily employed. In this study, a flow-through high-pressure deposition cell was used to measure the deposition rate of asphaltenes from a problematic field in the GOM under realistic conditions of pressure, temperature and composition. The impacts of shear (corresponding to the production rate in the field), residence time of the fluid in the cell, pressure, and chemical injection on the asphaltene deposition rate were investigated. Finally, the importance of these measurements for field production is discussed.
A Successful and Economic Way to Have the Right Professionals
Authors: Harker Andres Reyes , Saavedra Neston F. , Plata Willington A.
Published: October 2009

High Price of oil brought new challenges to oil companies regarding the knowledge management and "humanware" policies. Ecopetrol, through the Research Branch of the company (Instituto Colombiano del Petroleo - ICP), designed and accomplished an aggressive and innovative strategy for creating strong relationship with the universities looking forward to assuring the necessary capabilities and human resources in a very competitive industry.

The first step was the definition of the critical knowledge and topics requiredfor the company to guarantee the future growing and a competitive international position. Themes as well stability, seismic processing, enhanced oil recovery, mature fields development, structural geology, stratigraphy, among others, were defined as key knowledge for the oil industry activity and development in Colombia. Cooperation agreements were signed with the universities for organizing research groups which would work with the following structure: Groups would be composed for undergraduate students from the 4 upper levels (education in undergraduate level in Colombia is structured in 10 periods, six months long each) and postgraduate students, in a sort of pyramidal structure.The group should have leader researchers from Ecopetrol and the university (at least 1 of each institution).Young researchers are recently graduated students, with specific responsibilities in research projects and leading groups of undergraduated studentsEcopetrol would give strategic guidelines and sponsor the projects proposed for the group leading the focus of the invested resources

This initiative started back in 2003, with 10 agreements with different universities. After 5 years of successful operation, Ecopetrol invested in 2008 a sum near to US$4 M in 32 cooperation agreements pointing to research projects of the company; 193 undergraduate and 185 postgraduate students are part of the research groups. More than 90 technical solutions have been provided to Ecopetrol and 8 software solutions were designed and currently are in operation in the company.

In addition to these results, the most important success of the program is the people; Ecopetrol have the possibility to select the educated professionals in strategic branches of knowledge that have supplied the company with the necessary human force to face the challenge of becoming and international competitor.
A Numerical Study of Performance for Tight Gas and Shale Gas Reservoir Systems
Authors: Freeman C. M. , Moridis G. , Ilk D. , Blasingame T. A.
Published: October 2009

Various analytical, semi-analytical, and empirical models have been proposed to characterize rate/pressure behavior as a function of time in tight/shale gas systems featuring a horizontal well with multiple hydraulic fractures. Despite a few analytical models as well as a small number of published numerical studies there is currently little consensus regarding the large-scale flow behavior over time in such systems, particularly regarding the dominant flow regimes and whether or not reservoir properties/volume can be estimated from well performance data.

We constructed a fit-for-purpose numerical simulator which accounts for a variety of production features pertinent to these systems — specifically: ultra-tight matrix permeability, hydraulically fractured horizontal wells, multiple porosity and permeability fields, and desorption. These features cover the production mechanisms which are currently believed to be relevant in tight/shale gas systems.

We employ the numerical simulator to examine various tight/shale gas systems and to identify/illustrate the various flow regimes which progressively occur over time. We visualize the flow regimes using both specialized plots of rate and pressure functions, as well as maps of pressure distributions.

We use pressure maps to demonstrate the various flow regimes and their transitions in tight gas systems. In a typical tight gas system, we illustrate the initial linear flow into the hydraulic fractures (i.e., formation linear flow), transitioning to compound formation linear flow, and eventually transforming into elliptical flow.

We explore variations of possible shale gas system models. Based on diffusive flow (with/without desorption), we show that due to the extremely low permeability of shale, the flow behavior is dominated by the extent of and configuration of the fractures.

This work expands our understanding of flow behavior in tight gas and shale gas systems, where such an understanding may ultimately be used to estimate reservoir properties and reserves in these types of reservoirs.
Installation and Operational Performance of Horizontal Solid Expandable Openhole Production Liners in Maximum Reservoir Contact Wells – Case Histories
Authors: Sanders Tom , Zhou Shaohua , Aramco Saudi , York Patrick , Joulaud Thomas , Teo Jeffrey , Gandikota Raju
Published: October 2009

Solid expandable liners have been used extensively over the past 10 years as drilling liners in the beginning to production liners in the recent years, where the expandable liner may become differentially or mechanically stuck as soon as it reaches the end of the planned wellbore section. This environment requires the liner to be cemented and expanded in one of the most (if not the most) challenging well conditions it can be subjected. The expandable liners discussed in this paper so far have shown most promising and successful field application status as production liners.

When an expandable liner that is not differentially stuck is expanded using a swage, it typically "shrinks" in length as it expands in diameter as part of material balance physics. This shrinkage is typically 4 to 6%. That is, if a 1,000 ft liner is expanded 5% in diameter, the expanded length would be reduced to ~950 ft. To compensate for this shrinkage, an additional length of liner is run to ensure that the final length of liner required is delivered. However, when the expandable liner becomes differentially stuck or cannot move along the length of the wellbore during expansion, it cannot gain the material for its growth in diameter from the liner's length. Therefore, the material volume change required is accommodated within the liner's wall and its connectors. This environment is considered one of the most strenuous a solid expandable liner can be subjected to during expansion.

By combining insightful engineering with a stringent qualification regime of the expandable system and the tubulars and connectors that it uses, solid expandable production liners can be installed successfully that will service these types of challenging wells.

While extensive engineering and lab testing of an expandable system is critical, the ultimate testing is in multiple field applications to best develop effective reservoir sweeping of a mature field. Several case histories of field installations will be reviewed in this paper. The installation, zonal isolation, and tubular performance of these liners will be evaluated and reviewed using downhole tubular inspection logs, observed installation phenomenon, and performance over time. This empirical data will give the potential end users fundamental knowledge and good case history information on how to best qualify and use solid expandable liners for the ultimate benefit of gaining more oil production and reducing overall well cost.
New Slickline Smart-Release Tool Mitigates Wire-Recovery Issues in Extreme Well Conditions
Authors: Clemens Jack , Moore Darrell , Schram John , Foster Jerry , Garrett Johnnie
Published: October 2009

Traditionally, when wells in extreme environments required service, slickline, which had always been considered as the most cost-effective service option, was unable to provide the services because the available slickline tool options could not maintain integrity in the extreme well environments now being explored and developed. To address the requirements of the new scope of conditions in extreme environments, new methods that would meet a greater scope of needs were developed. The innovations include prejob wire-tension-modeling software and a state-of-the-art timed-release tool that provides successful intervention in difficult scenarios that normally could not have been considered as slickline candidates.

This paper will discuss these developments and how they have enabled slickline to be a more cost-efficient alternative for the operations that had to be performed by other service options when intervention was required in extreme depths or in or highly deviated wells.

A tool that can be timed to release the wire from the tool string at the rope socket without surface intervention has been developed to reduce the risks associated with stuck strings and dropping of conventional wire cutters. In addition, pre-job wire-tension modeling software is now available. How the newly developed slickline techniques can be used to mitigate the risks associated with the challenges created by the extremely deep and highly deviated wells will be discussed along with the enhanced cost efficiency and safety provided by these innovations. Implementation of the smart-release tool into the tool string will also be discussed.