bluuebunny/crossref_metadata_2025 huggingface dataset:
Air Injection and Waterflood Performance Comparison of Two Adjacent Units in Buffalo Field: Technical Analysis
Authors: Kumar V. K. , Gutierrez D. , Moore R. G. , Mehta S. A.
Published: December 2007

Buffalo Field covers a large area on the southwestern flank of the Williston Basin, in the northwest corner of South Dakota. In 1987, 8440 acres of the field were divided into two units to initiate improved oil recovery (IOR) operations with two different methods: air injection and waterflooding. After collecting 18 years of production history a comparison has been made between the two projects to determine the relative success of both units.

This paper addresses the technical performance of both projects in terms of incremental oil recovery, estimated ultimate recovery and incremental recovery per volumes of fluid injected. Ultimate primary recovery was estimated using conventional decline curve analysis on individual wells. Ultimate recovery was estimated by extrapolation of the current performance of the units assuming the same actual development scheme and operating strategies. Technical advantages and limitations of both IOR methods as applied in this field are also discussed.

Throughout the years, the West Buffalo Red River Unit (WBRRU) under air injection has shown a significantly superior performance over its "twin" West Buffalo "B" Red River Unit (WBBRRU) being waterflooded. Quicker production response to injection, higher production rates and higher incremental recovery are some of the advantages shown by air injection as an IOR method in this field.

This case study clearly shows the technical viability of air injection as an efficient method of improved oil recovery particularly in deep, high pressure, low permeability reservoirs where water injectivity is limited and other recovery processes become uneconomic.

The myth of air injection as a high risk, unsuccessful operation is shown to be invalid; and instead, it proves to be a feasible way to unlock oil accumulations.
Correlating Gel Rheology with Behavior during Extrusion through Fractures
Authors: Wang Y. , Seright R. S.
Published: December 2007

In many successful conformance control treatments, large volumes of gels were extruded through fractures during placement. The pressure gradient for gel extrusion depends strongly on fracture width and gel composition. Extrusion experiments directly measure gel properties in fractures, but they are both expensive and time-consuming. In this work, we investigated whether using rheology measurements to assess gel properties in fractures might prove a good substitute for the extrusion experiments, at a much more reasonable cost. The rheology behavior of the gels tested showed a strong parallel to the results obtained from previous gel extrusion experiments. However, for a given aperture (fracture width or plate-plate separation), the pressure gradients measured during the gel extrusion experiments were much higher than anticipated from rheology measurements. Extensive experiments established that wall slip and first normal stress difference were not responsible for the pressure gradient discrepancy. Steady shear and oscillatory shear data were collected with a rheometer using both smooth and rough parallel-plate geometries and employing various gap heights. Wall-slip effects were present with smooth plates but negligible with rough plates.

To explain the discrepancy, we noted that the aperture for gel flow (for mobile gel wormholing through concentrated immobile gel within the fracture) was much narrower than the width of the fracture. Considering the shear-thinning properties of the gels, two models were developed using shell momentum balances. The first model explained why the pressure gradient for gel extrusion varied inversely with the square of the fracture width rather than inversely with fracture width. In particular, the relationship depends on the power-law index of the material. The second model correlated pressure gradient, shear stress, flow rate, and shear rate to bridge the gap between gel rheology in fractures versus in a rheometer.
New Data Transmission Standard Facilitates Synchronous Remote Modeling and Surveillance via the Internet
Authors: Standifird W. , Baksh N. , Edwards S. , Wu V.
Published: December 2007

The communication of data between various operator and service company data stores has long been problematic. Fragile, low bandwidth lines of communication coupled with a lack of standards have left serious efficiency gaps in the movement of data from the acquisition location to decision-making and interpretation centers. Various systems have been developed and deployed to minimize these difficulties; however, all have fallen short of industry requirements. Recent availability of more robust, higher bandwidth lines between locations has led to a new standard of communication called Wellsite Information Transfer Standard Markup Language (WITSML). Using this new technology, data can be acquired and transmitted synchronously or asynchronously among multiple stakeholders with limited effort. The ability to mix and match various data collection vendors and connect these data sources to interpreters and modelers with limited effort is creating new opportunities to improve the success and efficiency of remote operations. This paper reviews four cases that demonstrate the use of WITSML to synchronously transmit real-time data from domestic and international offshore locations to onshore sites. The cases clearly demonstrate that WITSML meets previously neglected industry requirements of durability, flexibility, economy and ease of use in omni-directional data transmission between rig and shore.
Implementing Real-Time Asset Management: A Practical Perspective
Authors: Nordtvedt J. E. , Unneland T.
Published: December 2007

The Intelligent Energy domain is rapidly gaining attention within the oil and gas industry. Operators and service companies are currently transitioning from the initial envisioning phase to projects creating measurable value. However, there is still uncertainty regarding what needs to be done and what value it will actually bring. As a result, many assets experience organizational resistance to fully implementing efforts that can create value. This paper gives a practical perspective to field implementation of Real-Time Asset Management (RTAM) linked to the petroleum engineering work processes. We give practical illustrations and guidance on benefits from RTAM efforts including what work processes benefit most from integrating available technologies, and what steps are needed for implementing these in a RTAM setting. Examples are given to illustrate current challenges and success stories. Particular focus is on challenges and opportunities related to use of onshore operational centers, and how they will change the way we work in the future.
From Reservoir Through Process, From Today to Tomorrow—The Integrated Asset Model
Authors: Howell A. , Szatny M. , Torrens R.
Published: December 2007

Simulation technology from reservoir through process facility has advanced so much, that field development strategies can be developed within a new systematic workflow, using existing applications from many E&P departments. Detailed production data from many sources can be used within simulation models to give a good representation of future field wide behavior. In this paper a fictional case study of a reservoir that has been producing for some 12 years will be examined. The wells are all producing into a sub-sea manifold and then tied back via a 60km flow line and riser system. The reservoir is in severe decline with field production well below the original design capacity of the production system and surface facilities. Hence, further development options are being investigated for this asset. A new, nearby, reservoir has been discovered. A reservoir simulation model has been constructed for the new discovery. This second reservoir is a gas condensate system, much smaller than the existing reservoir and located 90 kms to the east. The current development plan shows six wells drilled and brought into production over an 18 month period. Reservoir 2 is a marginal development, the viability of producing this reservoir will depend on quantification of the reservoir uncertainty and finding a cost effective development strategy with existing processing facilities. The Business Development Team has suggested a number of possible options for developing this new reservoir; Option 1 involves tying in the new reservoir to the existing sub-sea infrastructure. Option 2 is to install a complete new flow line from the sub-sea template of the new reservoir and run this directly to the existing platform. But how do these options effect reservoir management and surface facilities performance? Evaluation is achieved by constructing an integrated asset model of the entire field, allowing the reservoir through facilities interaction to be evaluated in detail.
Gas Storage and Operations in Single-Bedded Salt Caverns: Stability Analyses
Authors: Han G. , Bruno M. S. , Lao K. , Young J. , Dorfmann L.
Published: December 2007

Bedded salt formations are located throughout the United States, providing valuable storage capacity for natural gas and other hydrocarbons. In order to increase gas storage capabilities and provide operators with improved geotechnical design and operating guidelines for these caverns, stability analyses of single bedded salt cavern have been completed and are described in this paper. This work is a part of integrated efforts initiated and sponsored by the US Department of Energy, Gas Technology Institute, and Pipeline Research Council International, Inc.

Numerical geomechanical models have been developed to investigate single cavern deformation and bedding plane slip for a variety of cavern configurations. A viscoplastic salt model has been developed based on an empirical creep law developed for the Waste Isolation Pilot Plant (WIPP) Program and combined with a Drucker-Prager model for damage and failure. The non-salt materials are described with either a traditional Mohr-Coulomb model, or an elastic model, depending on layer properties.

A baseline model with specified geometric dimensions is first selected and subjected to one year cyclic pressure operations. The amount of damage around the cavern wall and roof is evaluated and used as a comparison in the study. Then the operations are extended to 15 years to study cavern stability for long term gas storage and operations. In addition to the baseline model, parametric studies have been performed to investigate cavern damage as a function of salt roof thickness, overburden stiffness, interface properties, and cavern geometries. Each cavern simulation includes one year of pressure cycling with a minimum, mean, and maximum cavern pressure of 6.1 MPa (884.5 psi), 8.8 MPa (1276 psi) and 14.9 MPa (2160.5 psi), respectively. Different operation conditions, e.g. hydrostatic, cyclic, and a direct pressure drawdown, are compared and evaluated in terms of cavern stability.

These analyses can serve as a basis to select the best salt cavern candidate for gas storage and operations. They can also help to assess critical cavern design parameters for thin bedded salt formations.
3D Simulation of Rock Breakage With Air Hammers in Gas-Well Drilling
Authors: Han G. , Bruno M. S. , Dusseault M. B.
Published: December 2007

Air hammers have been used to drill gas wells in West Canada and Central USA since 1980s. Field evidence has demonstrated air drilling can be significantly improved with hammer bits in terms of Rate of Penetration (ROP), hole geometry, cost per foot, etc. However, inconsistent results in different formations, risks in operation, and economic uncertainties impede hammer acceptance and development.

In an effort to improve understanding of drilling physics and predict hammer performance, a 3D numerical simulator of air hammer drilling is developed in this study. The main features include an elastoplastic material model for rock constitutive behavior, a rock damage model for strength reduction and damage accumulation because of cyclic hammer impacts, multiple rock failure criteria for initiation of rock breakage, rock dynamic characteristics for energy dissipation and non-reflective boundaries. The numerical tool is further calibrated with the results from a series of single impact tests.

The simulation describes how rock behaves during the drilling, including stresses propagation inside the rock, deformation and damage evolvement, and breakage occurrence. It produces an estimation of ROP for different hammer energy and formation properties. The records of rock failure history indicate aggressive tensile failure may be primarily responsible for rock breakage in air hammer drilling, while compressive failure (or shear failure) may only contribute as a minor player.

These developments advance the simulation technology of hammer drilling and improve fundamental understanding of the physics involved. More importantly, the simulator can serve as a new tool to achieve a more predictable hammer performance.
Improving Storage and Workflow of Pressure-Related Information—Don't Lose Your Expert Community
Authors: Purdy C. , Webster J. , Brady K.
Published: December 2007

The next ten years are critical for managing manpower in the upstream petroleum industry. As experienced technical resources retire at an ever-increasing rate, companies are waking up to the reality that years of work and millions of dollars worth of knowledge and expertise is walking out the door.

In many companies, one person or a small community of experts are the only resource focusing on a particular discipline, such as pore pressure analysis or geomechanical modeling. Companies that have not developed or implemented solutions to combat the retirement challenge will be at a growing competitive disadvantage.

Factors surrounding data workflows and storage of pressure-related information within operating teams have been examined and show that data inaccessibility and inefficient data workflows have cultivated an environment where technical resources are unable to fully capitalize on available data. The current work environment does not allow past work to benefit current efforts and these factors are all at play in an industry that demands data sharing, collaboration and cross discipline cooperation.

By using existing technology and improved workflows it is possible to protect and benefit from the efforts of the retiring technical resources while improving the flow of information to the end user.

These storage and workflow challenges are reviewed for the pore pressure and geomechanical disciplines to demonstrate how better storage and data management translates into improved workflows and greater efficiencies among engineering and geological teams.
EOR Survey in the North Sea
Authors: Awan A. R. , Teigland R. , Kleppe J.
Published: December 2007

This paper provides a summary and a guide of the Enhanced Oil Recovery (EOR) technologies initiated in the North Sea in their period from 1975 until today. The five EOR technologies which have been initiated in the North Sea were hydrocarbon miscible gas injection, WAG injection, SWAG injection, FAWAG injection and MEOR. Each EOR technology which has been initiated in the North Sea was identified with its respective maturity level and / or maturing time frame, technology use restrictions and process efficiency on the basis of incremental oil.

Apart from WAG at Ekofisk and FAWAG at Snorre CFB, all technologies have been applied successfully on the corresponding fields. Hydrocarbon miscible gas injection and WAG injection can be considered as mature technologies in the North Sea. The most commonly used EOR technology in the North Sea was WAG and recognized as the most successful EOR technology.

The main problems experienced were injectivity (WAG, SWAG and FAWAG projects), injection system monitoring and reservoir heterogeneities (hydrocarbon miscible gas injection, WAG, SWAG and FAWAG projects). About 63% of all the reported EOR field applications have been initiated on the Norwegian Continental Shelf, 32% on the U.K. Continental Shelf and the remainder on the Danish Continental Shelf. Statoil was the leader in conducting EOR field applications in the North Sea. In the future, the majority of research will be conducted on microbial processes, CO2 injection and WAG (including SWAG) injection schemes.

In this review laboratory techniques, world statistics, simulation tools and economical evaluation was not considered and is outside the scope of this paper.
Implementing Chevron's i-field at the San Ardo, California, Asset
Authors: Ouimette J. , Oran K.
Published: December 2007

This is a case study of an integrated "digital oilfield" project. The San Ardo, California, i-field Project is one of a number of current Chevron i-field implementation projects. It seeks to transform how the San Ardo steamflood is operated, focusing on better decision making for the asset and streamlined work processes for heat, wells, and water management. The San Ardo i-field project is nearing the end of the planning and front-end engineering phases, with project execution starting in 2006. The project team created preferred alternatives for transforming 21 work processes. Decision support software would be integrated with improved instrumentation, workflow automation, and data architecture to enable more reliable and efficient field operation and execution of reservoir management targets. The project is integrated in two ways. First, integration occurs across the asset management value chain from reservoir through production optimization to day-to-day steamflood and facilities decisions and work processes. Secondly, it is integrated across technology. For example, reservoir surveillance signposts are created and used with computer models to move day-to-day decisions along correct trajectories for executing reservoir heating and production management. A common collaboration and visualization environment would be used for executing day-to-day field decisions. The knowledge provided in the paper would be helpful for assets where field operators are managing many wells with limited resources and attempting to improve their operability and efficiency.
Horizontal Wells Drilling in Vertical Lateral Beddings Successfully Tap the Upside Remaining Oil in Heavy Flooded Sandy Zones
Authors: Liu Bing , Sui Xinguang , Zhao Minjiao , Wang Jiaying , Ma Chi , Yu Xinghe
Published: December 2007

PI reservoir, the main reservoir of Daqing oilfield has an average thickness of 15-25metres with one-third OOIP of the total. This reservoir is highly flooded that their daily oil productivity is 4-5 tons /d per well, with a water-cut of 95%. But the current recovery degree of OOIP is only about 40 %, and one-third of the top thickness has not been tapped. Injected water circulating along the big channels can not further enlarge swept volume. In recent years, we drilled horizontal wells to recover the top remaining oil in the reservoir. Since muddy intercalation seldom develop within channel sand, this often results in fully flooded in horizontal wells by fast water breakthrough from the bottom to the topside of the reservoir as top remaining oil is produced.

This paper describes reservoir with geological model, and shows the internal architecture in the reservoir accurately. We use lateral muddy intercalations as barrier beds to prevent vertical flood along the wellbore, Once flood occurs, we perform water-plugging in specific lateral beddings. Let's take well N1-H25 for example, it was designed as a horizontal well with vertical lateral beddings. It was brought into production in Dec., 2004, initially it produced 123 tons per day, which was 22 times the production of any well in the same formation. In July 2005, its daily oil production was 81 tons, with a low water-cut of 28.9%. It has accumulated 26000 tons of oil by Dec. 2005. This well was designed to pass 8 lateral beddings, but in fact, it passes 16 lateral beddings. Its lateral muddy intercalation successfully prevented water flood along the wellbore, and effectively produced potential remaining oil in top highly flooded sand reservoirs.
Intelligent Monitoring? …. Add Borehole Gravity Measurements!
Authors: Loermans T. , Kelder O.
Published: December 2007

Borehole Gravity Measurement (BHGM) tools have been available for several decades, but until now, widespread applications were not possible. The current BHGM tools are too bulky to be run in almost any well without pulling the tubing. In addition, BHGM tools are limited to vertical wells and the existing sensors fall short on stability for permanent installation.

BHGM tools could be very useful for reservoir and production monitoring. First, the depth of investigation is enormous when compared to many other measurements. Advancing flood fronts, not only gas-water but even oil-water, could be detected from a distance of tens, hundreds or even beyond thousand feet from a well, if suitable BHGM sensors were available. Second, only very few parameters are needed to convert the raw gravity measurements, via a bulk density, to the main output: saturation. This avoids the challenges with several special parameters which are needed to arrive at saturation when using resistivity logs. Third, the interpretation models are simple: for gravity interpretation Newton's laws are perfectly adequate, while for resistivity and acoustic measurements, research on response functions is still ongoing.

We have modelled the response of BHGM tools in a number of typical Saudi Arabian conditions, including advancing oil/water fronts, coning and near well bore monitoring, proving the significant potential for BHGM technology. Hence, as there is a need for improved production and reservoir monitoring, further BHGM development becomes very attractive.

From an analysis of current day gravity sensors, several possible further development routes can be painted, each with its own advantages. It is clear that if our industry desires additional monitoring capabilities, it will be relatively simple to achieve intelligent monitoring by selecting the most appropriate route and developing those BHGM sensors, tools and related systems.
Three-Phase Upscaling in Capillary and Viscous Limit
Authors: Lohne A. , Virnovsky G.
Published: December 2007

Three phase flow properties are important for correct modeling and prediction of such IOR processes as WAG and blow-down/depletion after waterflooding. On the core-scale, these properties can generally be obtained directly from experiments, from pore-scale modeling of three-phase flow, or from empiric formulae (like the Stone's) interpolating two sets of two-phase data into the three-phase saturation region. For usage in simulators core scale properties have to be scaled up to reflect heterogeneities smaller than the simulation grid-blocks. These upscaled three-phase properties, similarly to their two-phase counterparts, are rate-dependent. We describe the upscaling procedure and efficient algorithms for three "easy-to-compute" asymptotic cases: VL-viscous limit (viscous dominance), CL-capillary limit (dominance of capillary forces), and VE-vertical equilibrium (flow dominated by gravity and capillarity).

Upscaled 3-phase relative permeabilities for different geological flow units from a North Sea field are analyzed. At VL, upscaled relative permeabilities to all phases will in general depend on two saturations if contrasts in relative permeabilities are present at the finer scale. This dependency may in many cases be small and ignored, but not always.

At CL, upscaled krw and krg will remain functions of one saturation each, as long as the oil phase is mobile in every part of the porous medium. When oil reaches its immobile saturation in part of the medium, both krw and krg will turn into full three-phase functions depending on two saturations. For the examples presented the size of the domain with full three-phase functions covers up to about half of the three-phase domain. The three-phase dependency was very weak for water in all the tested cases, while for gas very strong effects could be observed.
Efficient History Matching in Naturally Fractured Reservoirs
Authors: Gang T. , Kelkar M.
Published: December 2007

For naturally fractured reservoirs, history matching requires that both the matrix and fractures are properly characterized. Log and core data as well other static information can be very useful in building the matrix model. Some elements of the fracture model can be built using 3-D seismic data, well test data and production logging tool (PLT) data. However, field experience suggests that it is very difficult to properly quantify fracture permeability without matching production data. Currently, the procedure involves a trial and error method, where fracture permeabilities are adjusted manually to match the production data including water cuts and breakthroughs. One can adjust other parameters to match the data; however, fracture permeability (especially in the presence of large permeability contrast between matrix and fracture) represents first order effect in matching the production data.

This study focuses on the automatic history matching of production data by adjusting fracture permeablity in a static model. The methodology not only ensures geological consistency in the final model, but also includes uncertainties about fracture locations. The calculation of the sensitivity of the production data such as bottom hole flowing pressure, WOR and GOR etc. to reservoir model variables such as gridblock effective permeability, porosity and fracture/matrix coupling factor etc. is made efficient by an efficient direct sparse solver. Through building the relation between the fracture permeability and the reservoir model variables, the gradient of the production data to fracture permeability was estimated by chain rule. Through the transformation of reservoir model variables into the fracture permeability space for history matching, a significant time has been saved because of the reduction in parameter space.

The method is validated by conducting history matching for both synthetic and field data sets. The results show that this method is reliable and efficient for naturally fractured reservoir history matching.
Impact of Low-Cost Dilute Surfactants on Wettability and Relative Permeability
Authors: Rao D. N. , Ayirala S. C. , Abe A. A. , Xu W.
Published: December 2007

The decline of surfactant flooding can be attributed to the expense of reducing oil-water interfacial tension by several orders of magnitude. This study examines the potential for enhancing oil recovery by using low-cost surfactants to alter wettability. The wettability alterations by the surfactants have been characterized using contact angles and oil-water relative permeabilities. Core flooding experiments were conducted using three different rock-fluids systems: (1) Berea sandstone, Yates stocktank crude oil, Yates synthetic brine; (2) Yates dolomite rock, Yates stocktank crude oil, Yates synthetic brine; and (3) Yates dolomite rock, Yates live crude oil, Yates synthetic brine. Two types of surfactants, one nonionic and the other anionic have been used for wettability alteration. The experiments with Berea were conducted at ambient conditions, while dolomite rock tests were conducted at Yates reservoir conditions of 82°F and 700 psi. Contact angles were measured using Yates reservoir fluids and dolomite crystal surfaces using the Dual-Drop Dual-Crystal technique and oil-water relative permeabilities were computed by history matching oil recovery and pressure drop data from the coreflood experiments.

The shifts in relative permeability ratio curves indicate the ability of both surfactants to develop mixed-wettability in Berea sandstone cores. In the Yates dolomite rock, Yates stocktank oil and Yates brine system, both surfactants altered wettability from an initially strongly oil-wet to a weakly oil-wet state. For Yates live oil containing rock-fluids system, the nonionic surfactant altered the wettability from an initial weakly water-wet to a mixed-wet state, while anionic surfactant resulted in wettability alterations to a strongly oil-wet state. The contact angle measurements corroborated well with oil-water relative permeabilities to confirm the wettability shifts except for Yates live oil containing system with nonionic surfactant, where contact angles indicated wettability alterations to an intermediate-wet state. This study thus demonstrates the relative benefits of surfactant-induced wettability alteration mechanism to develop either intermediate or mixed wettability in reservoir rock-fluids for significant oil recovery enhancements.
A Study of Wetting Behavior and Surfactant EOR in Carbonates With Model Compounds
Authors: Wu Y. , Shuler P. J. , Blanco M. , Tang Y. , Goddard W. A.
Published: December 2007

This study focuses on the mechanisms responsible for enhanced oil recovery (EOR) from fractured carbonate reservoirs by surfactant solutions, and methods to screen for effective chemical formulations quickly. One key to this EOR process is the surfactant solution reversing the wetting of the carbonate surfaces from oil-wet to water-wet conditions. This effect allows the aqueous phase to imbibe into the matrix spontaneously and expel oil bypassed by a waterflood.

This study used different naphthenic acids (NA) dissolved in decane as a model oil to render calcite surfaces oil-wet. Because pure compounds are used, trends in wetting behavior can be related to NA molecular structure as measured by solid adsorption, contact angle and a novel, simple flotation test with calcite. Experiments with different surfactants and NA-treated calcite powder provide information about mechanisms responsible for sought after reversal to a water-wet state. Results indicate this flotation and a calcite chip cleaning test are rapid screening tools to identify better EOR surfactants for carbonates.

The study considers the application of surfactants for enhanced oil recovery (EOR) from carbonate reservoirs. This technology provides a new opportunity for EOR, especially for fractured carbonate where waterflood response typically is poor and the matrix is a high oil-saturation target for this process.
Mechanistic Study of Interaction between Water and Carbonate Rocks for Enhancing Oil Recovery
Authors: Gomari K. A. R. , Karoussi O. , Hamouda A. A.
Published: December 2007

The aim of this paper is to demonstrate the important role of ion composition for successful oil recovery by water injection and it also suggests possible mechanisms by which different ions interact with the carbonate rocks to alter the wettability.

Injected water contains, among other ions, sulfate and magnesium ions. The possible wettability alteration mechanisms of the calcite surface by Mg2+ and SO42- to more water-wet is addressed in light of contact angle measurements, and surface potential.
Combustion Front Behavior in Porous Media With Catalytic Agents
Authors: Adagulu G. D. , Akkutlu I. Y.
Published: December 2007

Several experimental investigations have previously considered naturally occurring clays, metallic minerals and additives as catalytic agents to improve oil recovery during air injection and in-situ combustion processes. It is reported that these materials could change the morphology and surface properties of the porous medium ahead of the combustion front; thus, (1) increase hydrocarbon deposition ahead of the front, and (2) modify the kinetics of oxidation reactions inside the front. However, their on the combustion front dynamics has not previously been investigated under varying reservoir conditions. In this paper, we approach the problem using an analytical method based on large activation energies of the oxidation reactions. The model describes combustion front as a moving boundary layer in a uniform porous medium. It involves coherent propagation of low-temperature (fuel-generating) and high-temperature (fuel-burning) reaction regions under the influence of reservoir heat losses; thus, it is suitable for investigating the role of catalytic agents on the front propagation. In the absence of these materials, it has been previously found that the reaction regions propagate closely spaced, thus reducing the influence of deleterious heat losses on the combustion front [6,7]. At low air injection rates, however, the peak temperature and propagation velocity of the front noticeably decrease; namely, the front approaches its extinction limit. Here, we propose that any possible improvement (whether catalytic or not) on combustion performance should preclude the observed temperature drop with the low injection rates. The presence of catalytic agents is consequently introduced to the model in terms of systematic variations in the reaction kinetics parameters, and deposited hydrocarbon/generated fuel amounts. It is found that, although kinetics influences the system dynamics, it may not improve the combustion performance due to a compensation effect. The improvement is rather due to an implicit role of the increased specific sand grain surface area on the hydrocarbon deposition ahead. The surface area promotes fuel deposition; hence, significantly increase total heat content of the combustion process in the reservoir. The work is important for developing guidelines to screen catalytic agents that could be used during the air injection processes.
Laboratory Experiments of Tertiary CO2 Injection Into a Fractured Core
Authors: Darvish G. R. , Lindeberg E. , Holt T. , Utne S. A.
Published: December 2007

The efficiency of tertiary CO2 injection at the reservoir conditions into fractured cores has been investigated experimentally. The experiment was designed to illustrate the process of water imbibition and CO2 injection into a North Sea chalk reservoir.

The core and core holder assembly were designed to allow a 2 mm gap to surround the core simulating a fracture. Live reservoir oil was prepared and used to saturate the matrix system. Due to the large permeability contrast between the core (4 mD) and the fracture it is not feasible to saturate the core by simply flooding the system with live oil, since oil would flow through the fracture and only partially saturate the core. To overcome this problem a unique technique has been developed for saturating the matrix system with reservoir fluids. This method ensures a homogeneous fluid composition within the pore system before the fracture system is initialized by the injection fluids (water/CO2).

During the experiment, the matrix system was first saturated with the live reservoir oil, during which the gap was blocked by a sealing material. In the next step the sealing material was removed and water was injected into the gap. Finally CO2 was injected at a low and constant rate into the gap. Oil and water production and fluid composition were monitored and the results show that injection of CO2 could significantly recover residual oil after water injection.
Development of Surrogate Reservoir Models (SRM) for Fast-Track Analysis of Complex Reservoirs
Authors: Mohaghegh S. D. , Modavi A. , Hafez H. H. , Haajizadeh M. , Kenawy M. , Guruswamy S.
Published: December 2007

Reservoir simulation has become the industry standard for reservoir management. It is now used in all phases of field development in the oil and gas industry. The full field reservoir models that have become the major source of information and prediction for decision making are continuously updated and major fields now have several versions of their model with each new version being a major improvement over the previous one. The newer versions have the latest information (geologic, geophysical and petro-physical measurements, interpretations and calculations based on new logs, seismic data, injection and productions, etc.) incorporated in them along with adjustments that usually are the result of single-well or multi-well history matching.

A typical reservoir model consists of hundreds of thousands and in many cases millions of grid blocks. As the size of the reservoir models grow the time required for each run increases. Schemes such as grid computing and parallel processing helps to a certain degree but cannot close the gap that exists between simulation runs and real-time processing. On the other hand with the new push for smart fields (a.k.a. i-fields) in the industry that is a natural growth of smart completions and smart wells, the need for being able to process information in real time becomes more pronounced. Surrogate Reservoir Models (SRMs) are the natural solution to address this necessity. SRMs are prototypes of the full field models that can run in fractions of a second rather than in hours or days. They mimic the capabilities of a full field model with high accuracy. These models can be developed regularly (as new versions of the full field models become available) off-line and can be put online for automatic history matching and real-time processing that can guide important decisions. SRMs can efficiently be used for real-time optimization, real-time decision making as well as analysis under uncertain conditions.

This paper presents a unified approach for development of SRMs using the state-of-the-art in intelligent systems techniques. An example for developing an SRM for a giant oil field in the Middle East is presented and the results of the analysis using the SRM for this field is discussed. In this example application SRM is used in order to analyze the impact of the uncertainties associated with several input parameters into the full field model.
Dynamics of Two-Phase Immiscible Pulsed Flow
Authors: Ivanov D. A. , Araujo M.
Published: December 2007

Cyclic waterflooding has received recent attention since many studies and field tests have shown that it may lead to additional oil recovery at virtually zero additional cost. Even though the process is in principle very similar to conventional waterflooding, there are interesting new effects taking place under the pulsed conditions that need to be properly quantified for a realistic field deployment of the cyclic injection process.

Two-phase immiscible pulsed flow experiments performed on homogenous packed glass beads cells are compared with flow behaviour under continuous injection. In the pulsed experiments, injection is switched on/off using a timing device in the pumping system. Symmetric cyclic periods and different injection rates were used in the study. Initially the dry packed cells were flushed with CO2 and saturated with water. This was followed by injection of oil up to leaving the cells at irreducible water saturation conditions. Then water was injected and the amount of produced fluids measured. Separate experiments under continuous and pulsed injection conditions with visual monitoring of fluid displacement were performed.

It is found that the amount of oil recovered at intermediate stages (after breakthrough and less than 3 pore volumes of injected water) is larger for the pulsing mode. The final recovery for both injection processes is similar within the experimental error. In the pulsed experiments, during the off injection period, spontaneous fluid spreading was observed leading to smoother displacement fronts compared to continuous injection. Also, displacement fronts were found to be more stable under pulsed conditions. The study concludes that residual oil saturation under pulsed injection can be reached earlier than under continuous injection, a result very attractive for field application. Experimental findings of this work shed light in the design of cyclic injection processes.
Identification of the Source of Low-Salinity Water Produced from a Subsea Well in the Birch Field and Implications for Scale Management
Authors: McCartney R. A. , Coghlan G. , White A.
Published: December 2007

Interpretation of produced water analyses is a relatively inexpensive method of obtaining a wide range of information that can be used to aid scale management, constrain the reservoir model, provide information on barriers to flow and zones of connectivity in the reservoir, and identify zones of water production in wells. In this paper we report on the interpretation of produced water analyses to help understand why unusual low salinity water was produced from well Z3, a sub-sea well in the Birch Field with two production zones (Brae Conglomerate and Ryazanian Sandstone), when production was re-started in March 2004 after a three-year shut-in period. In this case, of particular interest were the implications for future scale management on the well.

We have shown that the low salinity water is likely to be formation water from the Ryazanian Sandstone. Production of this water from well Z3 is declining over time, which may reflect the limited extent of the Ryazanian Sandstone, a nearby barrier to flow or calcium carbonate deposition adjacent to the well during pressure drawdown. Future water production from well Z3 is expected to be dominated by production from the Brae Conglomerate with production from the Ryazanian Sandstone only being important after lengthy shut-in periods. Current squeeze treatments are based on pre-development scaling predictions and have been designed to prevent moderate barite deposition. These treatments are likely to mitigate the mild barite scale deposition predicted to be associated with future production of water from the Brae and Ryazanian intervals. As the future scaling potential is predicted to be much less than originally planned for, the possibility of reducing the current MIC or discontinuing future squeeze treatments is being considered. Further work is required to fully assess the carbonate scaling risk associated with mixing of these waters but there are currently no indications that carbonate scale is forming in the well.

This study has demonstrated the value of interpretation of routinely collected produced water analyses in that it helped us understand and act on significant changes in produced water compositions from a sub-sea well without resorting to an expensive well intervention.
Near-Critical Gas/Condensate Relative Permeability of Carbonates
Authors: Calisgan H. , Demiral B. , Akin S.
Published: December 2007

The productivity of most gas condensate wells is reduced significantly due to condensate banking when the bottom-hole pressure falls below the dew point. The liquid drop-out such gas wells leads to reduced gas relative permeability and thus to low recovery problems. An understanding of the characteristics of the high-velocity gas-condensate flow and relative permeabilities is necessary for accurate forecast of well productivity. In order to tackle this goal, a series of relative permeability measurements on a moderate permeability carbonate core, using a binary retrograde condensate fluid sample were conducted near miscible conditions. The experiments used a pseudo-steady-state technique at high pressure and high velocity, measuring relative permeability under conditions similar to the near well region of a carbonate gas-condensate reservoir. Furthermore, the flow of gas and condensate at different force ratios (capillary and bond numbers) are investigated. It was observed that relative permeability depended on fluid composition and flow rate as well as condensate and water saturations. It was observed that as the flow rate of wetting phase (condensate) increased or the interfacial tension decreased, relative permeability curves shifted to left. It was found that a simple three-parameter mathematical model that depends on a new dimensionless number called condensate number successfully models the gas-condensate relative permeability data. The developed model resulted in a good agreement with published gas-condensate relative permeability data as well as end point relative permeabilities and saturations.
Gas/Water Flow in Porous Media in the Presence of Adsorbed Polymer: Experimental Study on Non-Darcy Effects
Authors: Blanchard V. , Lasseux D. , Bertin H. , Pichery T. , Chauveteau G. , Tabary R. , Zaitoun A.
Published: December 2007

The mechanism of Disproportionate Permeability Reduction (DPR) resulting from polymer or gel adsorption in porous media has been widely reported in the literature in the domain of Darcy regime. However, very few studies have been dedicated to the impact of polymer adsorption in porous media when two-phase flow occurs in non-linear regimes which are of interest in a wide range of applications. The objective of this paper is to report some experimental investigations on the effect of polymer adsorption on gas-water flow at low mean pressure, i.e. when Klinkenberg effects (or gas slippage) must be considered, as well as at high flow rates when inertial effects are significant.

The experimental study reported in this paper consists of water and nitrogen injections into various silicon carbide model granular packs having different permeabilities. More specifically, the purpose is to investigate gas flow at different water saturations before and after polymer adsorption over flow regimes ranging from slip flow to inertial flow. In good agreement with previous works, in the Darcy regime, we observe an increase in irreducible water saturation and a strong reduction in the relative permeability to water while the relative permeability to gas is slightly affected. At low mean pressure in the gas phase, the magnitude of Klinkenberg effect is found to increase with water saturation in the absence of polymer, whereas, for the same water saturation, the presence of an adsorbed polymer layer reduces this effect. In the inertial regime, a reduction of inertial effects is observed when gas is injected after polymer adsorption, taking into account water saturation and permeability modifications. Experimental data are discussed according to hypotheses put forth to explain these effects.
Generalized Horizontal Well Inflow Relationships for Liquid, Gas, or Two-Phase Flow
Authors: Kamkom R. , Zhu D.
Published: December 2007

The analytical models for horizontal inflow performance relationships (IPR) are presented in this paper for different formation fluid types and different boundary conditions. Even though reservoir simulation models may give more accurate and detailed results of oil and gas well production, analytical models are commonly used in the field for quick, practical and reasonable estimation of well performance. The analytical models are especially attractive when working on single well design and performance optimization. Similar to vertical well models, the analytical models for horizontal wells are developed for specific conditions. The IPR equations for horizontal wells are categorized into two boundary conditions; the steady-state flow condition (constant boundary pressure) and the pseudo-steady-state flow condition (no flow at the boundary). For each condition, the IPR equations for oil and gas wells are presented. Two-phase flow correlations for horizontal well IPR are also presented for the pseudo-steady- state condition. The results from different models are compared in the paper, and the limitations and appropriate applications of the IPR equations are discussed in the paper.

For each fluid system, examples illustrate how flow behavior varies with the flow regime. Examples also show the effect of critical parameters on inflow performance for horizontal wells. These equations are invaluable for reservoir and production engineers in their daily practice in horizontal wells.