bluuebunny/crossref_metadata_2025 huggingface dataset:
Development and Field Application of a New, Highly Stable Emulsified Acid
Authors: Nasr-El-Din Hisham A. , Al-Dirweesh Saad , Samuel Mathew
Published: September 2008

Acid-in-diesel emulsified acid has been used in the oilfield for many years. It is known that the emulsified acid should be stable at ambient conditions for a long period of time. It should be stable also at downhole conditions for a period of time long enough to pump the acid without encountering operational problems. Application of emulsified acid at higher temperatures requires 20 to 30 gpt of a cationic emulsifier.

A thorough laboratory study was conducted to select an emulsifier that can be used at lower loadings, and meet the stability criteria that are needed to stimulate oil and gas wells. Laboratory work included measuring stability, apparent viscosity, and droplet size distribution as a function of emulsifier type and concentration, temperature, and additive type and concentration.

A new emulsified acid was developed and used to acid fracture over ten wells in a deep gas reservoir in Saudi Arabia. The formation is predominantly limestone and dolomite with streaks of anhydrite. Acid fracturing practices consist of pumping 28 wt% emulsified acid (acid to diesel volume ratio = 70:30), a pad and in-situ gelled acid to create long conductive fractures.

The new emulsified acid used a significantly lower amount (4 to 6 gpt) of the emulsifier, albeit it produced a stable emulsion over a wide range of temperatures (from 75 to 275?F). The droplet size of emulsions produced from the new emulsifier was much smaller and, as a result, the apparent viscosity of the acid-in-diesel emulsion was higher. Field data showed greater reduction in the time needed to prepare the new emulsion in the field. The performance of wells stimulated with the new emulsifier was significantly better than those stimulated with the old emulsifier.
Modeling Leakage Through Faults of CO2 Stored in an Aquifer
Authors: Chang Kyung Won , Minkoff Susan E. , Bryant Steven L.
Published: September 2008

For secure storage of CO2 within geologic formations, the integrity of caps – overlying strata that are impervious to CO2 – is an important factor. Geologic structures, notably faults and the damage zones surrounding them may provide a conduit for CO2 to escape through a cap. If the fault encounters shallower permeable formations, the CO2 rising along the fault can enter them. This lateral migration would attenuate the rate at which CO2 enters sensitive formations such as aquifers used for drinking water. Thus, CO2 leakage along faults will have three behaviors: upward migration from the storage formation along a fault, lateral movement from the fault into permeable layers, and a continued but attenuated CO2 flux along the fault above the layers.

Here we develop a quasi-1D single-phase flow model for these three behaviors. The model is highly simplified and intended to be suitable for inclusion in a certification framework for geologic storage projects. The model accounts for flow from the fault into a permeable formation using a leakoff coefficient. The coefficient can vary spatially and depends on the geometry and petrophysical properties of the formation. We apply a commercial simulator to verify the quasi-1D model. A series of examples illustrates the controlling mechanisms for leakage rate from the reservoir and its attenuation by flux into shallower layers.

Nonlinearities arise even in this simple model. For example, leakage flux and the degree of attenuation vary nonlinearly with the permeability of the fault and the permeability of the shallower layer(s) intersected by the fault. Layers nearest the CO2 storage formation produce the most attenuation. But the percentage of CO2 entering overlying formations from the fault varies linearly with the ratio of fault permeability to leakoff coefficient. A simple estimate of the leak-off coefficient compares favorably with 2D, full-physics simulations. If the permeable layer is dipping, CO2 enters it asymmetrically and estimating the leakoff coefficient is less straightforward. The difference arises because of preferential flow within the layer (CO2 in the upper part, water below).
Screening Strategy for Chemical Enhanced Oil Recovery in Wyoming Basins
Authors: Alvarado V. , Thyne G. , Murrell G. R.
Published: September 2008

This paper presents results of a screening procedure for chemical EOR methods based on fuzzy-logic and data clustering algorithms. EOR processes considered included combinations of polymer, alkali and surfactant. Reservoir parameters are represented as triangular distributions with validity limits for each EOR process, and a most likely validity value of the distribution. Another triangular distribution was used as a reference for each of the reservoir and fluid parameters. The limits of validity were defined by mining a database and also by using technical limits, e.g. maximum stability temperature for polymers. The most relevant variables were dictated by availability of data and by comparing screening results with reported field cases. Wyoming basins have a long tradition of oil and gas exploitation, so many of the assets are at an advanced stage of maturity. The current energy market has revitalized the opportunities for further exploitation of numerous reservoirs in Wyoming. Enhanced-Oil Recovery (EOR) represents an attractive target for increasing the recovery factor in many of currently underexploited reservoirs, particularly by CO2 and Chemical Flooding. Associated decision-making workflows demand screening procedures, simulation and detailed economic evaluations. Sensible screening procedures are necessary to guide decision-making exercises. In practice, it was not possible to generalize success in field cases. Our results show this simple screening procedure requires a relatively small dataset for each asset, which contains bounds and likely values for the relevant rock and fluid properties. This has been implemented in a way that facilitates its use by final users. Many of the Wyoming reservoirs represent good candidates for processes such as alkaline-polymer or straight-polymer flooding, based on published field experience and our results. This EOR screening strategy is viewed as a significant improvement over go-no go criteria based on look-up table methods, because the developed method yields indicators ranking candidates for chemical EOR strategies. This provides a more assertive search for EOR candidates and allows reservoir types to be grouped on the basis of suitability. A similar philosophy will be developed for screening of CO2 projects, providing a further step in the decision making process and risk management associated with CO2-based EOR projects.
Extreme Production Logging in Long Horizontal Wells with High Flow Rates using Downhole Tractors
Authors: Castillo H. C. , Turner D. R. , Smalley E. A.
Published: September 2008

Some of the most important aspects to consider during the design, construction and productive life of a well are the amount and nature of the risks associated with the conveyance of downhole instruments to acquire critical formation-evaluation data while the hole is open, and downhole toolstrings needed to monitor or service the well after installing the completion and production hardware.

Wells with horizontal sections in excess of 5,000 ft present significant challenges to the existing well intervention methods and technologies; in particular, production-logging programs under high-production rates using downhole tractor conveyance have proven to be particularly difficult to plan and execute in these wells.

This paper describes the extreme conditions offered by these long horizontal wells, the underlying physics that support modeling of mechanical and hydraulic lift forces, the hazards present when conducting logging operations under flowing conditions using wireline and downhole tractors, the relevant conveyance risk-reduction technologies and methods to successfully plan and execute these extreme operations.

To demonstrate the operational merits and practical aspects of the methods and solutions presented, a case study based on a real operation is included.
Artificial Lift Selection Strategy for the Life of a Gas Well with Some Liquid Production
Authors: Oyewole Peter O. , Lea James F.
Published: September 2008

The Natural Gas industry is often faced with the challenge of selecting an optimal Artificial Lift method for a well in the midst of various artificial lift type choices. These challenges become more complex with increasing dynamic changes in well characteristics over the life of a well. This paper presents a case study on artificial lift selection strategy for unloading liquid from gas well in San Juan basin located in Southwestern, Colorado, and Northwestern, New Mexico. Various modeling techniques were applied to evaluate the lowest bottom hole flowing pressure for various Artificial Lift system types and wellbore geometry. Real life data acquired at the field trials was used to validate model results. The selection strategy resulted in the creation of a robust artificial lift selection matrix and charts for various well configurations as well as production rates for optimum well performance. This approach has a significant impact on gas well production; often loaded up with liquid and prematurely abandoned, due to lack of proper artificial lift strategy. The paper may assist the gas well operator and the need to adequately design, install and operate an optimum artificial lift system for the life of the gas well.
Multiphase Loop Tests for Subsea Separation-Unit Development
Authors: Pagnier P. , Noik C. , Maurel P. , Ricordeau A. , Volle J. L.
Published: September 2008

As flow assurance is a critical point, challenging offshore field development led TOTAL and IFP to manage a large R&D program on multiphase flow behaviour. One of the objectives is to improve the understanding of the behaviour of gas/oil/water mixtures in separation tanks. In the framework of a joint project, a new test facility platform GOwSP (Gas Oil water Separation Platform) was implemented in 2006 on the IFP-Lyon site. The issue consists in improving the design of separator as operators are now faced with more difficult operating conditions related to deep offshore or difficult crudes. The GOwSP is an industrial closed loop test facility designed for R&D program and for testing multiphase equipment such as separators, pumps or flow-meters. The loop includes a large three-phase storage tank (10m3). Gas and liquids are flowing separately towards a mixing point by the way of a compressor and centrifugal pumps. The mixture is sent to the multiphase equipment to be tested before coming back to the storage tank. The loop is completely equipped with basic instrumentation to qualify both the different in/out fluids and the tested equipment: flow meters on each single phase line upstream and downstream from the device, pressure transmitters, temperature sensors, two viscometers and two gamma densimeters. Moreover specific instrumentation is implemented inside the tested separator: two interface probes allow to determine flow hydrodynamic behaviour and phase composition (foam, emulsion). The GOwSP is under pressure and temperature control (Pmax 55bars, T°Cmax80°C). Fluids used are crude oil, salted water and natural gas with flows up to 15m3/h for fluids and 22 Am3/h for gas.

First tests on GOwSP were performed to characterise a vertical gas-liquid separation unit. The tested equipment consisted in a vertical scaled-down separator tank placed downstream two parallel pipes of different diameter and length. Then, tests on a horizontal separator were performed. Preliminary results are presented for several operating conditions of pressure, flow-rates, oil viscosity, mixing-rates and liquid levels.
Broadening the Application Range of Water Shutoff/Conformance Control Microgels: An Investigation of Their Chemical Robustness
Authors: Cozic Céline , Rousseau David , Tabary René
Published: September 2008

The performances of water shutoff and conformance control microgels were extensively investigated in previous works. Microgels are polymeric particles which are preformed, stable, fully water soluble and size controlled with a narrow size distribution. They are also non toxic, satisfying the OSPAR environmental tests. Microgels allow a controlled Permeability Reduction to water through their adsorption as monolayers. When injected in a multilayered reservoir, unlike conventional polymer-based systems, they invade significantly less the low permeability layers, thanks to the low viscosity of their solutions as well as to steric effects. Their penetration in the highest permeability layers is thus largely improved. Microgel technology was successfully applied in 2005 for the treatment of an underground gas storage reservoir: results were very positive in terms of water shutoff and sand control.

However, a broad range of potential applications cases for microgels involve harsh conditions such as high salinity reservoir brines. This paper is principally aimed at studying how high salinity impacts microgel treatment efficiency.

Solubility of microgels was first evaluated in an extended domain of brine salinities (up to 200 g/L NaCl with a high content of calcium). Viscosity measurements and filterability tests through calibrated membrane filters were performed, and led to specifications for optimum microgel dissolution.

Injections in granular pack models were then carried out with microgels diluted in brines of various salinities and at various microgels concentrations. These tests allowed to assess the injectivity and to determine the permeability reductions. After injection, the packs were flushed with different brine salinities. Such a procedure reproduces setting a well back in production after a microgel treatment. Results showed that the hydrodynamic thicknesses of adsorbed layers did not vary significantly when microgels were injected in brines of moderate to high salinities. At very high salinity (200 g/L NaCl with calcium), a shear-controlled over-adsorption of the microgels was observed. Results also showed that adsorbed layers were very stable when exposed, after microgels adsorption, to brines of low to very high salinity.

These positive results are due to the crosslinked structure of the microgels. They highlight once again their excellent chemical stability compared to linear polymer based systems. They bring new encouraging insights for the success of the microgels applications to come.
Observations From a Fieldwide Pressure Data Acquisition Campaign in the Wara Formation of the Greater Burgan Field, Kuwait
Authors: Ambastha Anil , Dashti Qasem , Maizeret Pierre-David , Al-Farhan Farhan , Bou-Mikael Sami , Rajan Sasi
Published: September 2008

The Wara reservoir has been producing for over 60 years and its pressure has slowly decreased over the years, now below saturation pressure in some structurally-high areas where gas cap has increased in size compared to very small initial gas caps in these areas. A peripheral, water injection project is being considered to maintain the pressure above bubble point and improve oil recovery from the flank areas. However, limited information is available concerning Wara reservoir heterogeneity. Shut-in of all Wara producers provided an "once-in-a-lifetime" opportunity to carry out a fieldwide pressure data acquisition campaign. Over a period of six months (Nov. 2006-May 2007), 127 static bottom-hole pressure (SBHP) surveys, 26 pressure buildup (PBU) tests (including buildup tests for 2 active wells of the interference test program) and 3 interference tests were conducted. Each interference test involved one active well and 3-6 observation wells. This paper describes a systematic methodology to select wells to test on a fieldwide basis, test design exercise, data acquisition program execution, and observations and conclusions reached from this data set.

Over the duration of the campaign, an increasing pressure trend was observed in almost all wells slated for PBU and interference tests. This observation was made possible due to multiple SBHP recordings in these wells. The linearly-increasing pressure trend had to be taken into account in the analyses of the buildup tests to avoid interpreting wrong boundary conditions. Wellbore dynamics also initially affected some pressure buildup tests and were later circumvented by the use of a downhole shut-in tool (DHST) to limit the phase segregation effect. The transient analyses revealed different flow regimes, from infinite-acting radial flow, to dual-layer and radial composite with or without sealing faults. From the SBHP data, maps have been made to assist in identifying compartments. One interference test showed anisotropy which could be critical in the implementation of a water injection project. Overall, the interpretation of the data from this extensive data acquisition campaign has shed light on reservoir heterogeneities that have been integrated with changes made in a full-field, "Wara only", history-matched simulation model.
Development and Use of High Density Fracturing Fluid in Deep Water Gulf of Mexico Frac and Packs
Authors: Rivas L. , Navaira G. , Bourgeois B. , Waltman B. , Lord P. , Goosen T.
Published: September 2008

In the Gulf of Mexico, there has been an increase in the number of wells drilled to depths greater than 20,000 ft with bottomhole pressures exceeding 20,000 psi. These deeper wells present drilling and completion challenges to the industry. Two of these challenges include fracture stimulation for low permeability and frac and pack sand control for higher permeability. Because of the high fracture gradient and friction in the wellbore tubulars, a conventional 1.0 to 1.04 SG fracturing fluid would require surface treating pressures greater than 15,000 psi. In the offshore marine environment, 15,000 psi pressure is the current limit of the flexible treatment line that transmits fluid from the stimulation equipment on the marine vessel to the wellhead on the rig.

To solve this limitation, a borate-crosslinked high-density fracturing (HDF) fluid with of up to 1.38 was developed to harnesses the power of gravity and reduce the amount of surface treating pressure required to achieve adequate bottomhole fracturing pressure without exceeding the safety limits of the surface equipment. In numerous wells, a minimum of 20% reduction in surface treating pressure over the conventional 1.04 SG was recorded.

This paper summarizes the well conditions, extensive fluid qualification testing, procedures, and selected job results along with final completion performance indicators.

The HDF fluid enables treatment of these deep offshore wells by lowering surface treating pressure. Conventional 15,000 psi equipment could be used, less horsepower was required, and creating a safer work environment was achieved.
Relative Permeabilities for Blowdown of a Near-Critical Oil Reservoir: Issues and Solutions Emerging From Pore-Scale Network Modelling
Authors: Bondino I. , Ezeuko C. C. , McDougall S. R. , Ward R. , Hamon G.
Published: September 2008

This work constitutes a practical attempt at addressing issues surrounding depletion gas-oil relative permeabilities in the case of a near-critical oil by using pore-scale network modelling techniques. Firstly a new model for gas buoyancy is presented that is able to track dynamically the movement of buoyant gas in the pore network; this framework is successfully used to model experimental visual observations of "coherent" channelized gas flow and dispersed "incoherent" gas flow that are seen to take place in porous media as permeability increases. We then apply the pore-scale network model to study the dynamics of gas flow during reservoir depressurization in virgin and waterflooded conditions with the dual purpose of understanding the microscopic flow behavior and producing predicted estimates for the variation of multi-phase flow properties: this is undertaken at two PVT extremes (fluid samples separated by a depth interval of 200m, from the top and bottom of the oil bearing column), and for two extremes of rock permeability (5mD and 252mD).

It is found that the very low gas-oil interfacial tension at the onset of the pressure decline induces strong gas buoyancy effects, even at the pore scale. Moreover, the variation in PVT properties along the oil bearing column, coupled to permeability differences, causes a transition of behaviours in the reservoir: from vertical gravity-driven gas flow in virgin systems, to more capillary-controlled, isotropic gas patterns under conditions of lower permeability, heavier oil, and/or high water saturation. In particular, under strong buoyancy conditions, anisotropy in gas flow during depletion is seen to be time dependent, with vertical gas flow at low gas saturations dominating the process initially. The gradual formation of a gas cap, however, slowly increases the extent of horizontal flow near the top of the system. In light of these observations, the issue of flow anisotropy and its impact on gas-oil relative permeability is examined in some detail by computing network fluxes in both the horizontal and vertical (along-gravity) directions.
Study of the PVT Properties of Gas—Synthetic Drilling Fluid Mixtures Applied to Well Control
Authors: Monteiro E. N. , Ribeiro P. R. , Lomba R. F. T.
Published: September 2008

The study of the interaction between the formation gas and the drilling fluid during offshore operations as well as in HPHT environment is essential to safely and economically drill the pay zone of the well. The environmental regulatory issues and the peculiar technical aspects involved in deep and ultradeep waters require low toxicity synthetic drilling fluids. The main objective of this study was to understand the PVT behavior of those fluids by the experimental determination and modeling of thermodynamic properties such as: solubility, specific gravity and formation volume factor of the fluid. Those properties have a direct impact on kick detection and circulation out of the well and should be addressed in well control planning and execution. The experimental work was conducted in a PVT lab, using mixtures of methane and n paraffin based emulsions as unweighted drilling fluids, tested at the temperatures of 158, 194 and 302o F. The pressure, temperature and fluid composition effects on those gas-liquid properties were analyzed and the experimental data for solubility and formation volume factor compared to predictions considering the additivity hypothesis and mathematical fittings based on the experimental data. A model for the methane and n paraffin system based on literature data and Peng-Robinson equation of state has also been fitted to the data in order to discuss the application of the additivity hypothesis for the emulsions. Pit gain evaluation based on the correlated experimental data for the synthetic drilling fluid has been performed and compared to the values expected for water based muds.
Glass Reinforced Epoxy Casing: Lessons Learned After Cementing and Completion of 70 Wells
Authors: Romera G. , Robles J. , Peacock H. , Morris W. , Peralta D.
Published: September 2008

The use of Glass Reinforced Epoxy (GRE) casing has increased significantly during the last decade, primarily on secondary recovery water injector wells. Corrosion resistance is this material main advantage when compared to steel. Almost one hundred wells have been completed in the Neuquén basin, Argentina, during the past five years.

This paper presents the experience obtained after cementing and completion of 70 GRE cased wells. Improvements on cement slurry mix designs, mud cleaning preflushes systems and best practices to ensure successful stimulation conditions (acids and fractures) are provided.

The work is supported by a laboratory study focused on the GRE casing to cement bonding performance evaluation and a finite element numerical simulation analysis of the down-hole service conditions achieved during stimulation jobs. This study considered the influence of GRE, cement and rock mechanical properties, the mud-cake removal conditions, as well as different bonding conditions. A comparison between GRE and steel cased wells is presented.

Cementing results were improved by casing centralization, increasing the preflushes aggressiveness and using low density slurries. Bonding experimental results showed that original GRE external coating attempts against cement bonding strength.

The numerical simulations show that when GRE casings are subjected to high internal pressures, its elastic behavior (Young modulus ten times lower than steel) generates overloading on the cement annulus. This condition could generate cracks that will propagate along the annulus creating communications paths between close perforated zones during stimulations treatments. This situation is even worst when poor formation mud-cake removal takes place.
The Impact of Effective Fracture Area and Conductivity on Fracture Deliverability and Stimulation Value
Authors: Brannon Harold D. , Starks Thomas R
Published: September 2008

The economic success of stimulated wells may be defined by the Return on Fracturing Investment (ROFI): the well performance relative to the cost of the hydraulic fracture stimulation employed. Hydraulic fracture deliverability is largely defined by the effective fracture area, which is that portion of the created fracture area exhibiting sufficient conductivity contrast within the productive reservoir interval. Previous studies demonstrating that stimulated well performance can be improved by increasing fracture conductivity have generally addressed characteristics of the proppant pack: optimized proppant properties, increased proppant size, increased proppant volume, and minimized damage to the created fracture permeability. Improving overall fracture area has typically been addressed by employing larger treatments and proppant volumes. Thus, previous approaches to enhancing fracture deliverability have resulted in increased stimulation cost, which, unless accompanied by a similar scale of increase in well productivity, has negative implications on ROFI.

The decades-old theory of increasing fracture deliverability by placing proppant in partial monolayers (PMLs) rather than multi-layer packs was resurrected in 2004 with the introduction of ultra-lightweight (ULW) proppant. The theory states that a partial monolayer exhibits conductivity equivalent to 15 to 20 layers of proppant in a packed fracture, which equates to a difference in areal proppant concentration of greater than 20X. In addition to enabling placement in a partial monolayer, the transportability of ULW proppant has been shown to provide greatly increased effective fracture area. Case histories of PML fracturing treatments have consistently illustrated stimulated production increases well beyond expectations, effectively validating the productivity benefits of the process.

The focus of this paper is to characterize the ROFI implications of PML designs using ultra-lightweight proppants in comparison to typical packed fracture designs using conventional proppants. Advanced fracture modeling will be used to illustrate the effects of fracture conductivity (proppant type, concentration, & damage) and effective fracture area on well performance. Normalized stimulation costs of the respective designs will be assessed against the resultant fracture deliverability and projected ROFIs.
Survivability of Optical Fiber for Harsh Environments
Authors: Ramos R. T. , Hawthorne W. D.
Published: September 2008

Today, optical-fiber systems are used in the oilfield for sensing and telemetry applications. The most commonly used downhole is the distributed temperature sensing (DTS) system which collects permanent real-time temperature well logs. These logs are extremely useful for real-time production allocation, heavy oil thermal recovery (e.g., steam-assisted gravity drainage, SAGD), steam-well management, and well-integrity monitoring.

Unfortunately, optical fibers are not immune to degradation under downhole conditions. Hydrogen, present in the wells because of corrosion or other factors, can attack the optical-fiber components causing attenuation increase. This attenuation can have a negative effect on the performance of the system, such as decreasing accuracy or resolution. Understanding the process and the impact of this degradation is of great importance to the reliable operation of these optical-fiber systems.

This article shows how a combination of controlled testing and modeling calculations can be used to provide an estimation of the attenuation increase expected from the fiber with time and downhole conditions.

Test results for attenuation of optical fiber in hydrogen atmospheres and under downhole temperatures will be shown. The article also provides results from the testing of a new optical fiber that was designed to give a considerable improvement in resistance to hydrogen attack. These results give an order of magnitude improvement in comparison with commercially available optical fibers. Early field tests are consistent with the results of the study.
Screen Development to Withstand 4,000-psi Overbalance, Subhydrostatic Completion in Deepwater GOM Subsea Waterflood Injector Wells
Authors: Gillespie George , Hinnant Chuck , Davis Chris , Schober Jamie , Darring Mike
Published: September 2008

This paper describes challenges, test equipment, test program and results in the development of a screen product and contingency fluid-loss control (FLC) pill formulation to withstand 4,600-psi burst resistance pressure.

In maturing deepwater fields, such as Shell Ursa/Princess where depleted reservoir pressures are significantly below the hydrostatic pressure of a seawater column, a modified screen design was required since screen products currently available were limited to <3,500 psi. FLC pill formulations also required modification because they were only validated to 1,000 psi in the current laboratory test apparatus.

A series of burst tests were conducted on a wire-wrap screen design direct wrapped to 4-in. base pipe. The objective was to determine if the screen could withstand at least 4,600 psi without damage. The wire-wrap design selected to improve the pressure rating was substantially heavier than what has been used in traditional sand-control completions. Initial burst tests with available 316L material averaged 4,600 psi. Two sets of additional burst tests were conducted with Alloy 625 screens on 25 Chrome base pipe to meet injector material requirements. The FLC formulation was modified from conventional design to enhance the pressure response. The last test results averaged over 5,100 psi.

Comprehensive before and after measurements and slot inspections were done; the data were used in Finite Element Analysis to finalize the detailed screen design. No traditional mechanical burst of the screen occurred. Most influential factors were slot size/geometry and pill formulation.
Analytical Upgridding Method to Preserve Dynamic Flow Behavior
Authors: Hosseini Seyyed Abolfazi , Kelkar Mohan
Published: September 2008

Geo-cellular model contains millions of grid blocks and needs to be up-scaled before the model can be used as an input for flow simulation. Available techniques for upgridding vary from simple methods such as proportional fractioning to more complicated methods such as maintaining heterogeneities through variance calculations. All these methods are independent of the flow process for which simulation is going to be used, and are independent of well configuration. We propose a new upgridding method which preserves the pressure profile at the upscaled level.

It is well established that more complex the flow process, more the detailed level of heterogeneity is needed in simulation model. In general, ideal upscaling is the process which preserves the "pressure profile" from the fine scale model under the applicable flow process. In our method we upgrid the geological model using simple flow equations in porous media. However, it should be remembered that to get a better match between fine scale and coarse scale, we also need to use appropriate upscaling of the reservoir properties.

The new methodology is currently developed for single phase flow; however, we used it for both single phase and two phase flows for 2D and 3D cases. The methodology fundamentally differs from the other methods which try to preserve heterogeneities. In those methods, grid blocks are combined which have similar velocities (or other properties) by assuming constant pressure drop across the blocks. Instead, we combine the grid blocks which have similar pressure profiles. The procedure is analytical and hence very efficient, but preserves the pressure profile in the reservoir. The grid blocks (or layers) are combined in a way so that the difference between fine scale and coarse scale pressure profiles is minimized. In addition, we also propose two new criteria that allow us to choose the optimum number of the layers more accurately so that critical level of heterogeneity is preserved. These criteria provide insight into the overall level of heterogeneity in the reservoir as well as effectiveness of the layering design.

We compare the results of our method with proportional layering and King et al.'s method (King 2005) and show that, for the same number of layers, the proposed method better captures the results of the fine scale model. We show that the layer merging not only depends on the variation in the permeability between the grid blocks, but also on relative magnitude of the permeability values. We also show that new method can account for additional variables such as grid block thicknesses and the size.
Development of Gas/Oil Miscibility in Water and Gas Injection
Authors: LaForce Tara , Orr Franklin M.
Published: September 2008

In this paper we use analytical solutions to study the development of multicontact miscibility in simultaneous water and gas (SWAG) injection into a reservoir containing a mixture of hydrocarbons. Application to CO2 storage and enhanced oil recovery is considered. We consider fully compositional one-dimensional (1D), four-component, three-phase flow through a porous medium.

Solutions are constructed for a vaporizing gas drive at a pressure below and above the gas/oil minimum miscibility pressure (MMP). We demonstrate that miscibility does not develop when the fraction of water in the injection mixture is sufficiently high and define the minimum gas fraction (MGF) necessary to achieve miscibility.

SWAG injection when a mobile water phase is present in the reservoir initially is also studied. We show that the MGF necessary to achieve miscibility depends on the fraction of water present in the reservoir at the start of SWAG injection. In all cases the relative permeability of the supercritical CO2 and water phases determine the MGF. These results indicate that, unlike in miscible gas injection, in SWAG injection the development of miscibility is dependent on the multiphase flow parameters, not just the phase behavior, and highlights the importance of improved relative permeability models.
Determination of Structural Dip and Azimuth from LWD Azimuthal Propagation Resistivity Measurements in Anisotropic Formations
Authors: Fang S. , Merchant A. , Hart E. , Kirkwood A.
Published: September 2008

With the use of both azimuthal propagation resistivity main and cross component data, the resistivity anisotropy and its dip and azimuth angles of a massive formation (anisotropic shale or laminated sand) can be determined. The accuracy of the determined parameters depends on the amount of available data. A minimum amount of data are two frequency main components and real and quadrature cross components. The boundary effects will distort the solution eventually; however, the anisotropy enhanced processing will minimize the effects to extend the algorithm to a certain distance away from a boundary.
Pore Pressure Coefficient Anisotropy Measurements for Intrinsic and Induced Anisotropy in Sandstone
Authors: Al-Tahini Ashraf , Abousleiman Younane
Published: September 2008

In this study, we determine experimentally the effect of inherent and stress-induced anisotropy on stiffness components, elastic moduli, and Biot's pore pressure coefficients (PPCs) for Lyons outcrop Colorado sandstone which exhibits a clear transverse isotropic rock structure. Both dynamic and quasi-static methods were used under a non-hydrostatic state of stress to perform the measurements on dry core samples. Our assumption of apparent transverse anisotropy was initially confirmed with acoustic velocity measurements and at a later stage in the loading with experimental transverse anisotropic failure analysis. The objective of this study is to identify and isolate the effect of stress-induced anisotropy from the inherent transverse anisotropy on the measured stiffness components, elastic moduli, and Biot's PPCs. The effect of stress-induced anisotropy appears to have significant control on measured stiffness components, elastic moduli, and Biot's PPCs as compared with the inherent transverse anisotropy effect. Our work shows that the stiffness components, Mij, thus computed elastic moduli, are highly influenced by the stress-induced anisotropy especially the off-diagonal stiffness components, M12 and M13, where the increase in their magnitudes from the dynamic measurements prior to failure is determined to be 100% and 81%, respectively. The difference in the magnitude between the axial and lateral Biot's PPCs, in line with bedding planes and perpendicular to them, is measured to be 24% and 16% from the quasi-static and dynamic methods, respectively; whereas, the effect of stress-induced anisotropy reduced the dynamic average magnitude of the Biot's PPCs along the bedding planes and transverse to these planes by 63% over a stress range of 145 MPa.
Semianalytical Representation of Wells and Near-Well Flow Convergence in Numerical Reservoir Simulation
Authors: Kurtoglu B. , Medeiros F. , Ozkan E. , Kazemi H.
Published: September 2008

This paper presents a new approach to compute wellbore pressures and near-well flow convergence in numerical reservoir simulation. In this semi-analytical approach, the solution of the flow problem in porous media is related to the boundary-element formulations. To account for reservoir heterogeneity, solution domain is subdivided into internally homogeneous reservoir blocks, which may include wells, and the solutions are coupled with the requirement of flux and pressure continuity at the block boundaries. Knowing the boundary values of the solution domain, this formulation solves for the flux at the block boundaries and flux and pressure on wells. Knowing the flux boundary condition, this formulation also enables the solution of pressure at any point within the reservoir blocks. This feature of the solution serves the purposes of multiscale simulation of flow and transport in porous media. Although the solution can be applied on field scale, this paper focuses on the applications to near-well flow convergence region. When the solution is used for the near-well flow-convergence region, the required boundary values of the solution domain can be obtained from any standard solution techniques, including finite-difference simulation, by accounting for wells as source terms.
Multilaterals Drilling and Sustainable Openhole Production From Theory to Field Case Studies
Authors: Hoang Son K. , Abousleiman Younane N. , Al-Tahini Ashraf
Published: September 2008

Drilling and production optimization are two interconnected operations for successful well construction and reservoir management, in particular for extended reach of multilateral wells. Formation damage, especially permeability reduction induced during drilling, greatly affect well completion and future potential reserve production. Reservoir pressure depletion and the consequent increase in effective stresses around the well branches are the main reasons behind solid production or total wellbore collapse. Unfortunately, to date, analytical study for the stability of multilaterals has been very limited due to the complex geometry and stress state involved. This work entails a recently derived analytical solution to estimate the safe mudweight window for wellbore stability during drilling, as well as to predict the maximum pressure drawdown for a stable junction during production. The presented solution is capable of handling the complexity of 3D anisotropic state of stress as well as any mother and lateral size, inclination, and azimuth. The study shows that the design of multilateral junction, especially inclination and azimuth of both wellbores with respect to regional in-situ stresses play a crucial role in the multilateral junction stability and the critical pressure drawdown estimation to prevent solid production and wellbore collapse. A field case study of a multilateral well drilled in the Khuff-C formation, Ghawar field, Saudi Arabia, is analyzed herein with drilling data, core-retrieved rock properties, and pressure drawdown and production estimates. The results showed alternate optimized completions that could have been applied early in the drilling and branching of the laterals. Practical guidelines concerning branching optimization have been established for junction planning and execution. The new analytical modeling has also been calibrated with a published peer-reviewed large-scale experimental program simulating both the anisotropy of far-field stresses and complex junction geometry with exceptional qualitative and quantitative results.
Wellbore Stability Performance of Water Base Mud Additives
Authors: Ewy Russell T. , Morton E. Keith
Published: September 2008

A critical property for many water-base muds is the ability to prevent near-wellbore pore pressure increase in shales. By slowing or preventing this pressure rise, a true overbalance pressure is maintained, which promotes wellbore stability. Using a device that simulates downhole rock stress and overbalance fluid pressure conditions, and using preserved shale samples, we tested four different muds containing different additives. Direct measurements of shale pore pressure vs. time were obtained, representing the pore pressure inside the wall of the wellbore. All muds slowed the loss of overbalance pressure compared to a base-case brine fluid, but two muds were very effective at slowing and/or preventing the loss of overbalance. One active mechanism appears to be an increase in the osmotic membrane efficiency, but permeability measurements conducted during these same tests show that physical plugging of the pore space is also an important mechanism for these two fluids. Measurements of fluid-induced swelling were also conducted in this same set of tests, and all four muds resulted in less swelling than the base-case brine. The most effective fluid was repeat-tested using a completely different shale, and it again was found to be very effective at preventing near-wellbore pore pressure increase.
Interpretation of Interwell Connectivity Tests in a Waterflood System
Authors: Dinh A. V. , Tiab D.
Published: September 2008

This study is an extension of a novel technique to determine interwell connectivity in a reservoir based on fluctuations of bottom hole pressure of both injectors and producers in a waterflood system. The technique uses a constrained multivariate linear regression analysis to obtain information about permeability trends, channel and barriers. Some of the advantages of this new technique are simplified one-step calculation of interwell connectivity coefficients, small number of data points and flexible testing plan. However, the previous study did not provide either in-depth understanding or any relationship between the interwell connectivity coefficients and other reservoir parameters.

This paper presents a mathematical model for bottom hole pressure responses of injectors and producers in a waterflood system. The model is based on available solution for fully penetrating vertical wells in a closed rectangular reservoir. It is then used to calculate interwell relative permeability, average reservoir pressure change and total reservoir pore volume using data from interwell connectivity test described in previous study. Reservoir compartmentalization can be inferred from the results. Cases of producers as signal wells, injectors as response wells and shut-in wells as response wells are also presented. Summary of results for these cases are provided. Reservoir behaviors and effect of skin factors are also discussed in this study.

Some of the conclusions drawn from this study are: (1) The mathematical model works well with interwell connectivity coefficients to quantify reservoir parameters; (2) The procedure provides in-depth understanding of the multi-well system with water injection in the presence of heterogeneity; (3) Injectors and producers have the same effect in terms of calculating interwell connectivity and thus, their roles can be interchanged. This study provides flexibility and understanding to the method of inferring interwell connectivity from bottom-hole pressure fluctuations. Interwell connectivity tests allow us to quantify accurately various reservoir properties in order to optimize reservoir performance.

Different synthetic reservoir models were analyzed including: homogeneous, anisotropic reservoirs, reservoirs with high permeability channel, partially sealing fault and sealing fault. The results are presented in details in the paper. A step-by-step procedure, charts, tables, and derivations are included in the paper.
Numerical Simulation and Sensitivity Analysis of In-Situ Fluid Flow in MRI Laboratory Waterfloods of Fractured Carbonate Rocks at Different Wettabilities
Authors: Haugen Åsmund , Fernø Martin A. , Graue Arne
Published: September 2008

Dynamic 3D MRI in-situ fluid saturation images during laboratory waterfloods of fractured carbonate rocks provided useful insights to the oil recovery mechanisms at water-wet and oil-wet conditions. The high spatial resolution imaging data formed the basis for a numerical representation of the experiment, and the numerical model was validated by history matching the experimentally observed results. Experimentally measured multiphase functions were used to match the in-situ fluid flow propagation during waterfloods of fractured rock, improving the confidence in the simulations beyond simply relying on material balance. A numerical sensitivity analysis of the effects from variations in fracture properties identified the impacts on sweep efficiency and oil recovery in waterfloods of fractured rock.