bluuebunny/crossref_metadata_2025 huggingface dataset:
Position/Fracture Uncertainty and Ranging During Drilling and Fracturing
Authors: Samuel Robello , Germain Olivier , Gang Rui
Published: October 2012

Unconventional shale drilling has developed rapidly during the last decade. The development of substantial prospectsespecially in shale gas playsrequires advanced technologies and prudent well monitoring. Many new operational challenges are associated because of simultaneous operationssuch as drilling and fracturing nearby wells.

While drillingthe interaction of the fractures from nearby wells results in pressure communication and unexpected well kicks. Because of the low porosity of those tight reservoirsthose uncommon well kicks have so far not been severebut taking the time to control wellbore pressures adversely affects the efficiency of the drilling process and increases the nonproductive time. Additionallyas fracturing becomes more efficientand conductivity increasespossible future events might have much more dramatic consequences. This paper presents a method that uses the positional uncertainty of the well being drilledpositional uncertainty of the fractured/fracturing wellsand uncertainty of the fracture length and fracture orientation to avoid this problem. The paper discusses the reasons and challengestechniquesand lessons learned to solve the simultaneous moving boundary conditions between the reference wells and multiple offset wells. The method of explicit solution avoids a trial-and-error procedure and provides excellent maneuverability of planning requirements. The modified model and methods provided the use of exact mathematical solutions and uncertainty ellipses estimates.

This method can also be used to monitor the influence of other variablessuch as temperature cyclingoil drainage distancewellbore storage effectand reservoir pressure transients. The method presented can be used in the planning stage to ensure optimal well placement; it can also be used for designing super fractures between wells. The study indicates that the use of real-time data from drilling and fracturing wells can predict the need for remedial action.
Experimental investigation of Pressure Drop/Flow Rate Relationship for Small Aperture Holes for High Viscosity Fluids
Authors: Jain Rachna , Long Ted A. , Dickson Jasper , Brown Scott V. , Shtepani Edmond
Published: October 2012

This paper studies the effect of viscosity and fines particle loading on the pressure drop across a 4mm orifice in a specific geometry built to mimic a representative well completion. In previous studies, most of these orifices have been validated experimentally for viscosities up to 200cp only for such completions. The current study focused on a wider viscosity variation (1cp – 3000cp) with lower flow rates (0.1m3/day - 30m3/day). The pressure drop was measured across the orifice and through the entire pipe assembly. The measured data was non-dimensionalized using the Euler number and plotted against the Reynolds number for all the rates and viscosities. The orifice pressure drop data overall agreed well with the limited data that was available from the literature. It was also compared and validated against commercially available CFD software. The effect of sand particle loading was also studied and its effect on apparent viscosity increase was measured in the laboratory. The pressure drop-flow rate relationship disclosed in this paper can be used to design effective completions for intermediate/high viscosity oil applications and will be able to predict the completions pressure drop more accurately.
Thermal Management of Electronics Used in Downhole Tools
Authors: Verma Sandeep , Elias Quincy
Published: October 2012

In the search for new oil and gas reservoirs, the industry is likely to drill, characterize, complete, and produce wells with a reservoir temperature higher than 150°C, which are considered to be high-pressure/high-temperature (HP/HT) wells. An increasing number of ultra-HP/HT (high-pressure, high-temperature) wells with reservoir temperature above 205°C are also likely to be drilled. Downhole tools experience high failure rates at these conditions since there is a limited catalog of conventional electronic components that can reliably operate above 150°C Active and passive cooling of electronics are options for extending the operability and reliability of downhole tools in HP/HT and ultra-HP/HT environments.

Passive methods provide cooling for a short duration because they are designed to provide a fixed capacity for heat absorption from the tool. Examples of such methods include the use of a flask (or vacuum-jacketed tool housing) and the use of phase-changing materials. If the tool is likely to be exposed to HP/HT or ultra-HP/HT conditions for a long duration, then the use of active cooling methods may become necessary. Active cooling methods use electric power to reject heat (absorbed from the tool) at relatively lower temperatures to the higher-temperature wellbore fluid (or the formation) by using a suitable heat pump or a thermodynamic cycle. It is important to choose the optimal thermodynamic cycle and working fluid so that the power consumption is minimized. We present a process analysis of various thermodynamic cycles and demonstrate that the vapor compression cycle is the most efficient thermodynamic cycle for cooling downhole tools. In addition, we present an analytical methodology to identify a suitable fluid for this cycle. Water was chosen as the fluid for the vapor compression cycle; it is environmentally friendly, easily available, and has a high latent heat of vaporization.

The vapor compression cycle was demonstrated in a part of a wireline formation tester tool. A special chassis was constructed that permitted flow of refrigerant through it. Heating elements and thermocouples were installed on the chassis to simulate heat dissipation from electronic components during operation. To simulate the high-temperature downhole environment, the tool was heated by two 4.5feet long, 2500 W jacket heaters. Steam was supplied to this chassis at different flow rates to balance the heat load at two reservoir temperatures. Heat generated on the chassis, and heat transferred across the vacuum-jacketed housing was absorbed by the refrigerant. This demonstrated that the vapor compression cycle is efficient and capable of actively cooling downhole tools.

Experimental results indicate that, using the vapor compression cycle with a refrigerant flow rate of 10 mL/min, it is possible to remove 175 W and 100 W of heat from the chassis when the tool is exposed to a reservoir temperature of 200°C and 250°C, respectively.
A Novel Technique for Wells that Require Gravel Packing for Sand Control and Inflow Control Devices for Managing Water Encroachment: Case Histories from Ocelote Field in Colombia
Authors: Velez Beatriz , Charry William , Duarte Anker , Beltran Alexander , Prent Larry , Rubiano John , Trujillo Hernando , Tengono Jose Aldemar , Castano Ricardo , Ortiz Everardo , Florez Darwin , Guerrero Ximena , Navarro Claudia , Stamm Bryan , Lopez Nicolas
Published: October 2012

Gravel packing is one of the commonly used sand control techniques in long openhole horizontal completions. Although numerous wells have been gravel packed with either one of the two placement techniques (α/β or shunt tubes), achieving a complete pack with sand control screens that have inflow control devices (ICD) can be challenging to say the least. This is because of the high pressure drops needed for the fluid to flow through the ICD into the base-pipe/wash-pipe annulus at the typical rates used for gravel packing, resulting in significant pressure rise and exceeding the fracturing pressure of the formation. Although using a screen without an ICD at the bottommost joint would certainly allow the α-wave to reach the toe, the pressure buildup will occur as soon as the β-wave proceeds upstream of that joint, which will either result in formation fracturing and bridging or significant rate reduction and α-wave height increase (near the heel first), both events resulting in a premature screenout.

Ocelote field in Colombia requires sand control, and gravel packing and standalone screens (SAS) have both been used in openhole horizontal completions in various parts of the field. An additional challenge in this field has been the premature water breakthrough from the aquifer leading to very high water cuts after only a few months of production. ICDs have successfully been implemented in SAS completions to address this challenge in other parts of the world. Similarly, gravel packing has been successful in controlling sand in parts of the field where SAS was considered unsatisfactory, although water cut in most of these wells increased to 70 to 90% after only 3 months of production.

In this paper, we present a novel technique for wells that require gravel packing for sand control and ICD functionality for managing water encroachment. Detailed in the paper is the first application of the proposed technique in Ocelote field, which resulted in 100% pack efficiencies using the water packing technique as well as significant reduction in water cuts, with substantial improvement in the project economics.
Added Value by Fast and Robust Conditioning of Structural Surfaces to Horizontal Wells for Real-World Reservoir Models
Authors: Stenerud Vegard R. , Kallekleiv Hans , Abrahamsen Petter , Dahle Pål , Skorstad Arne , Viken May Hege
Published: October 2012

Structural updates for a complex reservoir model require time-consuming manual work, therefore, updates are rarely performed. This leads to an outdated model that gradually loses its predictability. Eventually, this results in model breakdown, and a new model must be built from scratch. Continuously updatable reservoir models avoid this and increase the value of models as a tool in decision making. In addition, easily updateable structural surfaces enable several structural realizations for spanning the uncertainty.

We present the use of a method for fast and robust updates of structural surfaces in reservoir models. We will focus on updates using zone data from horizontal wells (zone-log conditioning), since this traditionally has been a bottleneck that needs tedious manual work prone to error. In zone-log conditioning, we try to generate horizon surfaces that honor the geological zonation along the well paths. This is important for property modeling, and is crucial for fluid-flow simulations. Our method is robust, fully automated, and is built on a consistent mathematical framework that includes specified input-data uncertainties. It has provided satisfactory results for large real-world reservoir models where standard methods and work processes have failed. The field example presented shows a reduction from 22.9 % to 0.9 % in incorrectly honoring of the zone logs by applying this method rather than the standard approach. The remaining 0.9 % is due to conflicting data, gridding errors, and is difficult to get rid of even with manual editing. We consider this a large step forward with respect to providing an up-to-date basis for decisions that also can account for structural uncertainties.
Buckling of Bouyancy Assisted Tubulars
Authors: Arslan Mehmet , Ozbayoglu Evren M. , Miska Stefan Z. , Yu Mengjiao , Takach Nicholas , Mitchell Robert F.
Published: October 2012

Use of buoyancy has emerged to provide multiple solutions to overcome the drag problem for wells with shallow and high step-out profiles. Although both full and partial floatation methodologies have been employed successfully to extend the reach in many field cases, the influence of buoyancy on tubular instability has not been investigated yet. This paper presents an extensive experimental and analytical study, focusing on static tubular instability inside horizontal wellbores with emphasis on buoyancy. In terms of the experimental research, running tubular into horizontal wellbores was simulated with four different pipes, varying buoyancy and loading speed. Throughout the tests, axial loads both applied to the pipe and transmitted through the pipe were recorded simultaneously, with respect to pipe displacement. Experiments reveal that currently existing models give reasonable approximations as long as buoyancy is not included into the tests. The major interpretation from experiments is such that contrary to what currently existing expressions imply, i.e. tubular buckles immediately as effective weight approaches zero; even for naturally buoyant conditions, considerable amount of axial load is still required for both buckling initiation and helix formation. As buoyancy increases further, results and predictions diverge from each other considerably. In order to eliminate the discrepancies between results and predictions, theoretical study was conducted. Empirical correlations that also consider the influence of buoyancy on critical buckling loads are presented. Finally, another pipe was also tested within different buoyancy conditions to validate the equations developed. Experimental results of this pipe closely match the new analytical findings. This experimental and analytical study provides useful results for future applications with buoyancy assisted tubulars, in terms of practical engineering and design calculations.
Fracability Index – More Than Just Calculating Rock Properties
Authors: Mullen Mike , Enderlin Milt
Published: October 2012

The geometry and complexity of hydraulic fracture stimulation treatments is largely controlled by the heterogeneous and anisotropic nature of rocks. Conventional practice in designing fracture stimulation treatments revolve around the parameters that can be changed and considers the rock being stimulated as homogenous and isotropic. Engineers can influence the frac geometry to some degree by changing the pumping rate, fluid viscosity and proppant loading. If the goal of a frac job is to get the fluid and proppant below the ground, most any formation can be frac’d. The degree to which a reservoir will generate complex fracture networks, break into fresh rock or create a simple bi-wing fracture can be influenced by the stimulation treatment job design. The creation of a complex fracture network is a function of the stimulation fluid rheology, rock properties and presence and orientation of preexisting planes of weakness acting in the stress state of the reservoir.

The index of brittleness or fracability is a term frequently used to describe formations that are likely to create complex fracture networks when fracture stimulated. In a broader view, fracability is much more than just calculating mechanical rock properties. A new definition of fracability, the Complex Fracability Index (CFI), proposed here integrates the sedimentary fabric, stratigraphic properties, mineral distribution and the presence and orientation of preexisting planes of weakness operating in the present day stress state into a single metric. This approach establishes a means to qualitatively or quantitatively determine the degree to which the rock will have the ability to create a complex fracture network or just a simple planer hydraulic fracture using the mechanical rock properties and the dip and orientation of the preexisting planes of weakness in the rock in the modern day stress state. The CFI methodology is not limited to shale reservoirs. Examples from the Barnett Shale and the tight sand in the Piceance Basin will be discussed.
A Fully-Coupled Free and Adsorptive Phase Transport Model for Shale Gas Reservoirs Including Non-Darcy Flow Effects
Authors: Xiong X. , Devegowda D. , Michel G. G. , Sigal R. F. , Civan F.
Published: October 2012

Accurate modeling of gas through shale-gas reservoirs characterized by nano-meter pores where the effects of various non- Darcy flow regimes and the adsorbed-layer are important is presented and demonstrated by several examples. Quantification of gas transport may be accomplished using the transport equation that is valid for all flow regimes. This equation though needs further modification when transport is through a media where the gas is adsorbed onto the pore wall. In the presence of adsorption, there is a pore pressure dependent loss of porosity and cross-sectional area to free gas transport. The apparent gas permeability correction is accomplished for various flow regimes using the Knudsen number by consideration of the reduction of the cross-sectional area to free gas transport in the presence of adsorption. We show that transport in the adsorbed layer may contribute significantly in the total gas transport in these nanopores. An effective transport model is presented to account for the impact of adsorption through two mechanisms. First, we modify the transport equation to account for the pore-pressure dependent-reduction in the volume available to free gas transport; second, we model transport through the adsorbed layer using Fick's law of diffusion. The coupled model is then compare to conventional transport models over a wide range of reservoir properties and conditions.

As pore-pressure is reduced, adsorbed phase gas desorbs into free gas and apparent permeability increases. The difference in the estimated apparent permeability with and without the consideration of the adsorption volume can be a factor of two or more at initial reservoir conditions. Diffusion on the surface of organic pores can be a substantial transport mechanism in shales depending on the pore connectivity, pore pressure, and pore size distribution in the organic pores. The interpretation of production data will be compromised without considering the effects of adsorption on apparent permeability. This work implies that permeability measurements for shale gas reservoirs must be done with methane at in-situ pore pressures. Because these corrections are pore-pressure not effective pressure dependent, effective pressure is not a valid parameter to use in quantifying the pressure dependence of these transport equations.
Capillary Pressure Prediction from Rock Models Reconstructed Using Well Log Data
Authors: Jin Guodong , Manakov Artem , Chen Jinhong , Zhang Jilin
Published: October 2012

Capillary pressure (Pc) is one of the main factors governing the hydrocarbon distribution within a reservoir. Its determination usually requires expensive, time-consuming laboratory experiments on a restricted number of core samples, while the continuous Pc profile of a well is practically derived from the nuclear-magnetic-resonance (NMR) downhole logging measurements. This paper presents a robust and inexpensive method of predicting the continuous Pc profile of a well from rock models reconstructed using various well log data. The approach first generates a representative rock model for the formation at each given depth of interest. The rock model is constrained by formation parameters derived from the logging data and accounts for diagenetic processes such as compaction and precipitation of carbonate and clay minerals. Simulations of fluid flow and primary drainage are then performed on rock models to determine the Pc curve and absolute permeability.

To test and validate our modeling approach, we select 16 sandstone core samples from various geologic settings to perform laboratory measurements and numermical simulations. Rock models are reconstructed using the measured grain-size distributions and grain mineralogy from core samples. The drainage Pc curves derived from rock models match well with laboratory measurements on the corresponding core samples, while Pc curves converted from NMR T2 distributions using the simple relationship of PcT2= ξ show differences in shape. Furthermore, the computed permeability of rock models show good agreement with the core permeability, mostly falling within the ± 2 times measurements. We have also applied the rock modeling technique to predict the continuous Pc and permeability profiles of a well. Formation grain-size distribution and mineralogy at each depth are derived from downhole measurements and used to generate rock models. Generally, our computed permeability falls within the same order of magnitude as the measurements on core samples from the same depth. The simulated Pc curves differ in shape from those converted from NMR T2 distributions. However, in this case it is unknown which one represents the real Pc curve due to the absence of laboratory core measurements.
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: October 2012

Unconventional gas is stored in extensive areas known as Basin Centered Continuous Gas Accumulations. While 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 multi-stage hydraulic fracturing in horizontal wells in three dimensions (3D) using 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 3D, 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 (Western Canada Sedimentary Basin).

Traditionally, the most widely used approaches have their roots in semi-analytical 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 due to pressure depletion results in more realistic production predictions when compared with the case where 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 nano-Darcy scale.
Three-Phase Compositional Modeling with Capillarity in Heterogeneous and Fractured Media
Authors: Moortgat Joachim , Firoozabadi Abbas
Published: October 2012

Capillary pressure can have a significant effect on multiphase flow in heterogeneous and fractured media, even when there is species transfer between the phases. Modeling the combined non-linearities from phase behavior and capillarity in the multiphase flow equations for heterogeneous and fractured media may be one of the most complicated problems in reservoir simulation. In this work, we present an efficient numerical scheme that uses higher-order methods for the first time to model capillarity in fully compositional three-phase flow. We introduce a simple local computation of the capillarity pressure gradients in the fractional flow formulation in terms of the total flux. Complications arising from gravity and capillarity are resolved in the upwinding with respect to phase fluxes. Our choice of the Mixed Hybrid Finite Element Method for the pressure and flux fields is an accurate and natural approach to compute the capillary pressure gradients and fluxes at the interface between regions of different permeabilities. We present various examples on both core- and large-scales to demonstrate powerful features of our capillary pressure modeling and the upwinding with gravity and capillary pressure. The examples include layered and fractured domains.
Remote Triggering of Large Events during Hydraulic Fracture Stimulations
Authors: Bowman S. , Urbancic T. , Baig A.
Published: October 2012

Hydraulic fracture stimulations result in the re-distribution of stress adjacent to the treatment well that in turn may result in the triggering of seismicity. Generally, seismicity only occurs when the triggering source, such as the injection of proppants, acts to drive the pre-existing stress field closer to failure levels of susceptible fractures/faults. If we consider that the observed seismicity is a function of the stress state and its interaction with the fracture network, under some conditions, it might be possible that seismicity may then occur at distances beyond the volume related to or directly influenced by the stimulation. Currently, the extent of seismic influence, including the potential for remote mobilization of pre-existing structures, the potential for out-of-zone fluid communication, and the relative stress and stress transfer conditions leading to large event occurrence (M > 0) are not well understood.

In this paper, we investigate the spatial and temporal variations in microseismicity associated with hydraulic fracture treatment of a shale play in North America during which distant larger magnitude events were triggered. These events, in this example, were located up to several hundred metres away from the stimulations, and in some cases in different formations from the reservoir host rock. These datasets, including calculated source parameters such as apparent stress and seismic moment, provide the basis for examining the conditions under which remote structures can be activated and how the distribution of microseismicty can be used to establish the region of stimulation influence. Based on these observations we postulate on the potential of triggering events remotely.
Pressure-Dependent Natural-Fracture Permeability in Shale and its Effect on Shale-Gas Well Production
Authors: Cho Y. , Apaydin O. G. , Ozkan E.
Published: October 2012

This paper presents the results of an experimental study of pressure-dependent natural-fracture permeability in tight, unconventional reservoirs. Bakken cores are used in the experiments. For the purpose of this paper, pressure-related permeability losses in hydraulic fractures and matrix system are not considered. Experimental data are used to screen the stress-dependent matrix-permeability correlations available in the literature for application to shale fractures. Selected correlations are matched with the data to delineate the reasonable ranges of the correlation coefficients for shale fractures. The applications of the correlations over practical ranges of pressure drop in shale reservoirs indicate over 80% reduction in fracture permeability, with most of the permeability loss occurring during the initial pressure drop. To appraise the effect of pressure-dependent natural-fracture permeability on shale-gas production, experimentally developed correlations are incorporated in an analytical model of a fractured horizontal well surrounded by a stimulated reservoir volume. The model is used to history match the performances of two wells in the Barnett and Haynesville formations. It is shown that the effect of pressure-dependent natural-fracture permeability on shale-gas-well production is a function of the permeability of the matrix system. If the matrix system is too tight, then the retained permeability of the natural fractures may still be sufficient for the available volume of the fluid when the system pressure drops.
Nano to Macro Mechanical Characterization of Shale
Authors: Kumar Vikas , Sondergeld Carl H. , Rai Chandra S.
Published: October 2012

We report on a nano-indentation study of shales from the Barnett, Woodford, Ordovician, Eagle Ford and Haynesville plays. Careful selection of load and displacement during nano-indentation testing yields micro to macro-mechanical properties, Young's modulus and hardness, of shale. Scanning Electron Microscope coupled and nano-indentation were used to study the mechanical behavior of kerogen. The measured Young's modulus of kerogen varied from 5 to 9 GPa. Mineralogy is found to play an important role in controlling mechanical properties of shales; an increase in carbonate and quartz content is correlated with an increase in Young's modulus whereas, an increase in TOC, clay content and porosity decreases Young's modulus. Close agreement is found between indentation moduli measured on small samples (mm scale) and dynamic moduli calculated from velocity and density measurements made on larger samples (centimeter scale). Tests conducted on cuttings provided results comparable to measurements made on larger core samples. Nano-indentation can provide a viable means of assessing quantitative measure of shale "fraccability."
A Combined Experimental and Theoretical Investigation on Application of Wettability Modifiers in Gas-Condensate Reservoirs
Authors: Fahimpour J. , Jamiolahmady M. , Sohrabi M.
Published: October 2012

Well productivity of gas-condensate reservoirs can be severely impaired by condensate/water blockage around the wellbore. Improving resident phase mobility by altering the rock wettability to intermediate gas-wet has been proposed as an efficient and long-term remedial solution to this issue.

Evaluating the performance of such a costly chemical treatment process for real field applications through experimental and theoretical investigations is crucial, something which has been addressed here. In this work different groups of chemicals were used to alter wettability of various carbonate rock surfaces. The impact of a number of important parameters on the reservoir performance was also studied in our numerical simulation exercise.

The main findings of performed experiments are: a) anionic and to lesser extent non-ionic fluorochemicals are effective wettability modifiers for carbonate minerals, b) by increasing the chemical concentration typically oil-repellency increases and water-repellency either does not change or decreases, c) permeability damage due to excess chemical deposited on mineral surfaces becomes more sever in low permeability rocks. Using alcohols instead of water-based solvent and/or filtration of chemical large aggregates can to some extent reduce the undesired rock permeability impairment and d) temperature has a significant albeit non-monotonic effect on the interaction between chemical and the rock surface, especially at its elevated limits.

Numerical simulation results demonstrated that alcohol (compared to water)-based chemical solutions have better performance, especially at higher volumes of the injected chemical and in tighter rocks due to the reduced adverse effect of solution back-flow. The improvement factor of relative permeability and durability of chemical treatment showed significant impact on increasing the benefits of such a process. On the other hand, reduction of the rock permeability due to excessive chemical deposition had considerable adverse effect on the treatment performance, especially when a water-based solvent was used.

These results provide valuable practical guidelines on design and application of such treatment solutions for field trials.
A New Three-Dimensional, Compositional, Model for Hydraulic Fracturing with Energized Fluids
Authors: Ribeiro Lionel H. , Sharma Mukul M.
Published: October 2012

While several three-dimensional (3D) fracturing models exist for incompressible water-based fluids, none are able to capture the thermal and compositional effects that are important when using energized fluids. This paper introduces a new 3D, compositional, non-isothermal, fracturing model designed for compressible fracturing fluids. The new model predicts changes in temperature and fluid density. These changes are treated on a firm theoretical basis by using an energy balance equation and an equation of state, both in the fracture and in the wellbore. The model is capable of handling any multicomponent mixture of fluids and chemicals. Changes in phase behavior with temperature, pressure, and composition can be modeled.

A new simulator has been developed based on the compositional model presented in this paper. The simulator is validated for traditional fluid formulations against known analytical solutions and against a well-established commercial fracturing simulator. Results from the new simulator are then presented for energized fluids such as CO2 and LPG. This tool is specifically suited for fracture design in formations in which energized fluids constitute a viable alternative to traditional fracturing fluids. This is notably the case in reservoirs that are depleted, under-saturated, or water-sensitive.
Cyclic Hysteresis in Three-Phase Relative Permeability Applicable to WAG Injection: Water-Wet and Mixed-Wet Systems under Low Gas/Oil IFT
Authors: Fatemi S. Mobeen , Sohrabi Mehran
Published: October 2012

One major problem in the prediction of the performance of Water Alternating Gas (WAG) process is the uncertainty associated with the changes in three-phase relative permeability (kr) values of oil, gas and water in different cycles, which is known as cyclic hysteresis. In this work we have investigated the effect of cyclic injection on three phase kr by performing a series of coreflood experiments under both water-wet and mixed-wet conditions. WAG experiments started with water injection (I) followed by gas injection (D) and this cyclic injection of water and gas was repeated (IDIDID). Three-phase relative permeabilities were obtained analytically from the coreflood data using an extension of Buckley-Leveret formula to three-phase flow.

The results show the importance of properly accounting for irreversible kr hysteresis loops (especially for gas and oil) in the processes involving cyclic injection under three-phase flow conditions. Gas relative permeability (krg) dropped in successive cycles under both water-wet and mixed-wet conditions krg hysteresis was larger in the water-wet system compared to the mixed-wet case. The results also reveal cyclic hysteresis for oil relative permeability (kro), which tends to increase in successive gas injection periods. The improvement in kro was larger in the water-wet system. In both water-wet and mixed-wet systems, the largest krw hysteresis happens for the transition from two-phase (oil/water system) to three-phase system (from 1st water injection into 1st gas injection) and the subsequent WAG cycles does not show much hysteresis for krw in our experiments.

The paper also offers insights into and explanations for the observed cyclic hysteresis behaviour based on our understanding of the pore-scale and core-scale displacement mechanisms involved in WAG injection. The results highlight some serious shortcomings of the existing reservoir simulators for reliable simulation of oil recovery processes involving three-phase flow and flow reversal.
Effect of Gas Diffusion on Mobility of Foam for EOR
Authors: Nonnekes L. E. , Cox S. J. , Rossen W. R.
Published: October 2012

Transport of gas across liquid films between bubbles is thought to weaken foam by increasing bubble size. It is cited as one reason why CO2 foams for enhanced oil recovery (EOR) are usually weaker than N2 foams and why steam foams are weaker than foams of steam mixed with N2. In porous media, diffusion can rapidly destroy bubbles smaller than a pore, but in EOR foam bubbles are thought to be larger than pores, making the role of diffusion moot. Previous analysis of diffusion in foam in porous media has focused on diffusion between immobile bubbles smaller than the pores.

We examine here the effect of inter-bubble gas diffusion on flowing bubbles in a simplified model of a porous medium (a periodically constricted tube) and in particular its effect on the bubble-size distribution and capillary resistance to flow. We use the solution for bubble shapes, curvatures and pressure differences between bubbles from previous studies of bubble movement through periodically constricted tubes to estimate the diffusion rate between bubbles. We fit our model parameters to mass-transfer data for foam films between bubbles and realistic convection rates and pore geometries for foam EOR processes. Bubbles somewhat smaller than a pore can indeed disappear by diffusion as the bubbles move. For bubbles larger than a pore, as expected in EOR, diffusion does not affect bubble size. Instead, diffusion actually increases capillary resistance to flow (i.e., makes foam stronger): lamellae spend more time in positions where lamella curvature resists forward movement.

When fit to pressures and diffusion and convection rates representative of field application of foams, diffusion is not expected to alter the bubble-size distribution in a foam, but instead modestly increases the resistance to flow. The reason for the apparent weakness of CO2 foam therefore evidently lies in factors other than CO2's large diffusion rate through foam.
Logging-While-Drilling Cement Evaluation: A Case Study from the North Slope, Alaska
Authors: Longo Joe , Hupp Douglas , Blyth Matthew , Alford Jeff
Published: October 2012

Alaska state requirements as well as sound engineering practice require that oil and gas operators investigate the zonal isolation in the annulus of water injection wells. Conventional cement evaluation can be a time-consuming and expensive process, especially in high-angle or horizontal wells in which the wireline tools must be conveyed with a tractor or on drillpipe. Cased-hole LWD sonic data was acquired in a North Slope, Alaska, well to evaluate the cement bond zonal isolation in the casing by attenuation and transmission analysis. The LWD data was compared with a traditional wireline cement evaluation logs to validate the application. This paper provides a case study of the techniques used to acquire process and interpret logging-while-drilling (LWD) sonic logs for cement evaluation.

In this case study, a horizontal lateral section was drilled after setting and cementing the intermediate casing string. The interval to be evaluated for zonal isolation was behind this intermediate casing. LWD sonic data were acquired for cement evaluation purposes while tripping in the hole to drill out the intermediate casing cement shoe prior to drilling the horizontal section of this well. The ability to acquire cement evaluation data during the normal drilling practice provides significant cost savings over traditional wireline cement evaluation methodologies.

This paper discusses the theoretical basis for using LWD sonic data for cement evaluation, planning procedures, data acquisition, and data processing. A comparison of the LWD sonic cement evaluation data with traditional wireline cement evaluation data that was used to validate this technique is provided. Additionally, the advantage of integrating the LWD cement evaluation option into the drilling process will be described.
High-Density Brine-Based Fracturing Fluid for Ultra-Deep Fracturing Stimulation
Authors: Gupta D. V. , Carman Paul , Venugopal Rupa
Published: October 2012

With the oil and gas industry looking ever deeper for hydrocarbons, well control and completions have become important challenges to overcome. Ultra-deep wells usually have pressured or over-pressured formations and require heavyweight brines to control hydrostatic pressures. Completions that once used fresh water or sea water are no longer feasible due to the much higher surface treating pressure requirements, which current equipment cannot sustain. Consequently, the industry has been interested in using heavyweight brines as a base for fracturing fluids. However, the practice is limited by the polymers that can be used in particular base brine. The most commonly used systems employ NaBr, usually in the range of 11.0 to 12.5 ppg, with a modified guar, buffer, crosslinker and other additives. The systems are finicky, hard to break and the NaBr brines have higher cost compared to chloride brines, prompting a search for alternative, less expensive solutions.

A newly developed system will viscosify any brine from 11.0 to 19.2 ppg, with only gellant, surfactant and breaker added on the fly to the base fluid. No buffer, crosslinker or other additives are necessary, which greatly improves operational efficiency, especially offshore. The unique patented polymer system creates an association with the salt solution to generate viscosity. The system can be used with lower-cost brines or blends based on NaCl, NaBr, CaCl2 and CaBr2. The resulting fluid is very elastic and has excellent proppant transport characteristics. The system can be broken efficiently to achieve good regain conductivity. This paper will present the chemistry and results of complete laboratory testing to evaluate the fluid for fracturing applications.
A Stable Fracturing Fluid for Produced Water Applications
Authors: Gupta D.V. Satya , Carman Paul , Venugopal Rupa
Published: October 2012

As shale fracturing operations continue to increase, so do the required volumes of relatively fresh water - which in some areas is limited in availability for fracturing. Exacerbating the issue, the water that is produced back after fracturing typically contains large amounts of total dissolved solids (TDS), including sodium, calcium, magnesium, barium and other salts. Storing and disposing of this water is becoming very expensive, and operators increasingly seek options for recycling and reusing this water. An ideal solution would be to reuse it in subsequent fracturing, but conventional fracturing fluid systems require fairly low TDS to achieve reliably stable rheology, so produced water typically requires extensive treatment before it can be reused for fracturing.

A new polymer system has been designed to viscosify produced waters a minimal filtration to eliminate large solid particulates. In addition to achieving stable viscosity despite the dissolved solids in the water, the system simplifies operations, requiring only a gellant, surfactant and breaker added on the fly to the water. No buffer, crosslinker or other additives are necessary. The unique polymer system uses a specialized surfactant to create an association with the produced water and generate viscosity. The resulting fluid is elastic and has excellent proppant transport characteristics. The system can be broken efficiently to achieve good regain conductivity. This paper will present the chemistry and results of complete laboratory testing to evaluate the fluid for fracturing operations. Testing will include demonstrations of fluid properties with typical produced water samples from the Bakken and Marcellus shales.
Explicit Calculation of Expansion Factors for Collision Avoidance between Two Co-planar Survey Error Ellipses
Authors: Sawaryn S. J. , Jamieson A. L. , McGregor A. E.
Published: October 2012

The positional uncertainty about a point on a wellbore is commonly represented as an ellipsoid. The ellipsoid also accounts for the dimensions of the casing or open hole. Using this model, at any time the resulting uncertainty about a wellbore along its trajectory is a curved, continuous cone. To a good approximation, the intersection of the plane normal to a reference well with these cones can be represented as ellipses. This simple geometrical model has been adopted by various standards organisations to define minimum acceptable separation distances between well bores, for example the Norwegian NORSOK D-10 standard.

Because of mathematical difficulties, the existing methods for calculating the resulting separation factors are only approximations and may be either too optimistic or too conservative, particularly for ellipses with high eccentricities. The paper presents explicit equations for determining the exact condition where the ellipses touch, expressing the result as an expansion scale factor. Methods are presented for the expansion of either one, or both ellipses, together with implementation notes and other associated tools. The new algorithms are only marginally less efficient than the existing approximation methods and they can be used to increase the allowable proximity of two adjacent wells whilst satisfying the geometrical and probabilistic constraints. The examples included in the paper illustrate this.

The proposed calculation method is consistent with existing industry wellbore uncertainty models. Since the determination of the osculating condition is exact, the calculation is neither too optimistic nor too conservative. This paper is a response to discussions held at the SPE Wellbore Positioning Technical Section meeting on 3rd November 2011.
High Reliability Gas Lift Flow Control Device Technology and Erosion/Endurance Tests
Authors: Xu Jun , Scott Stuart L. , Mabry Wayne , Gamboa Jose
Published: October 2012

High reliability gas-lift flow control devices (FCD) enable gas lift for wells with the potential for H2S in the produced gas and where casing is not qualified for H2S service. H2S is a potential for wells undergoing a waterflood, so the business impact of this technology is significant with the growing use of waterfloods in offshore fields. Specification of these valves is such that no leakage is allowed at both high (8000 psi) and low (1 psi) differential pressures across the valve. In addition, the extremely high intervention cost of subsea or TLP wells coupled with HSE challenge posed by sour fluid production in non-Shell qualified casing service require a higher level of gas-lift valve's reliability under this extreme environment. This paper describes the new technology of high reliability gas-flow control devises ensuring that the annulus volume is displaced only once. A series of testing programs were designed utilizing the ESS (environmental stress screen) concept and harsh test standard that greatly exceeds API specification for gas-lift FCD.

In 2009, Shell UA deepwater qualified three vender's gas-lift flow control devices using the Shell specified high reliability qualification standards. In 2010, Shell conducted valve cycling tests on the qualified valves at the Colorado Engineering Experiment Station. In 2011, Shell continued to work with Tulsa University to build up a new erosion testing facility and carry out a series of erosion/endurance tests on Shell qualified gas-lift flow control devices with Barite and water mixture. The purpose for Barite erosion tests was to determine if the Shell qualified gas-lift control devices can survive high density and high volume flow without the failure of the check system. This paper details the test procedures developed and some of the key findings of this qualification program.