bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Carbonate Well Production Enhancement Application for Encapsulated Acid Technology: First-Use Case History
Authors: Blauch M. E. , Cheng A. , Rispler K. , Khallad Abe
Published: December 2007

Production from carbonate wells is often controlled by the degree of stratigraphic interconnectivity or lack thereof. Formation stratigraphy results in severely compartmentalized reservoirs. Effective methods for achieving hydraulic interconnectivity with such compartments are limited in horizontal openhole and long pay section in deviated wells. A new technology is emerging that incorporates solid acid capsules that function as both a fluid-diverting agent and a fracture conductivity enhancer. The degradable sized particulate system is incorporated into the acidizing fluid designed to enhance inflow from natural fracture swarms and to help enable propagation of hydraulic fractures that can breach or achieve wellbore communication with the stratigraphic compartments.

This paper presents a case experimental project that involves a Canadian carbonate gas reservoir. Historically, horizontal wells drilled in low-permeability reservoirs with no natural fractures have shown poor production response. This successful production stimulation case demonstrates the potential to overcome the compartmentalization problem. In one of the first-use case wells reviewed in this paper, up to a 10-fold increase in reservoir pressure was observed in a shortterm buildup test, and the well was converted into an economic producer. Image logs were used to provide location and distribution of mineralized natural fracture swarms targeted for stimulation. Production data, laboratory data and post-treatment productivity index (PI) are presented.

This paper adds to the industry's technical knowledge base by: (1) offering a practical, lower cost, high value solution to a significant emerging market; (2) documenting the first use of a new technology application; (3) presenting evidence of the technology's widespread global application to carbonate reservoirs and possibly sandstone reservoirs.
Development and Validation of a Sandstone Acidizing Model with a New Permeability Response Model
Authors: Rodoplu S. , Zhu D. , Hill A. D. , Zhou H.
Published: December 2007

A large effort has been devoted over the years to modeling of the sandstone acidizing process. Yet, there has been little laboratory validation of the models that are being used. In fact, most comparisons between theoretical models and experiments are still made with just one set of laboratory results - those of Lindsay1 conducted with 3 inch Berea cores over twenty-five years ago. In this paper, we implement a rigorous model of the permeability response to a sandstone acidizing simulator. The permeability model includes the effects of changing rock morphology and mineral distribution on permeability prediction. We conduct a series of sandstone acidizing core flood tests, and verify the model by comparing it with new laboratory data. This comparison not only provides a validation of the permeability model, but also of the two-acid, three-mineral model of sandstone acidizing2, a commonly used model of the sandstone acidizing process. The applicability of the sandstone acidizing model to field applications is then illustrated by history-matching the actual response during a well treatment with the model.
Laboratory Study of Gas Trapping in Foam-Acid Diversion
Authors: Xu Q. , Rossen W. R.
Published: December 2007

A series of Berea coreflood experiments modeled the process of foam-acid diversion for well stimulation. Foam was injected to steady state, followed by injection of liquid to represent acid. Pressure gradient was monitored along the core and average liquid saturation was determined by weighing the core continuously during the experiments. This approach provides direct data on liquid saturation and liquid relative permeability during foam injection and liquid injection after foam.

Water saturation increased by a larger amount during postfoam liquid injection than estimated in previous studies. The liquid relative-permeability function krw(Sw) obtained during foam injection was reasonably accurate during post-foam liquid injection, until gas dissolution into the injected liquid became significant. The ultimate trapped-gas saturation during liquid injection appears to depend on previously injected foam quality; this may require a revision of models for the acid-diversion process.

It appears that a sufficiently high foam quality (injected gas fraction) can eliminate the detrimental decline in pressure gradient observed during liquid injection in earlier studies. This may alter previous ideas about the optimal foam quality for foam-acid diversion.
Modeling And Implementation Of A System For Sucker Rod Downhole Dynamometer Card Pattern Recognition
Authors: Schnitman L. , Albuquerque G. S. , Corrêa J. F. , Lepikson H. , Bitencourt A. C. P.
Published: December 2007

This paper presents a new method for the downhole dynamometer card pattern creation. This method use artificial intelligence concepts and real card data picked up from the oil fields acquired data. The main idea is to allow field team to generate patterns based on their own experience supported by an intelligent algorithm designed to perform graphical analysis of the card shape.

The main idea is to allow pattern recognition and its classification toward the solution of rod pumping problems in oil wells. Successful results were reached when the proposed method was applied in PETROBRAS/UN-BA real databases. Tests performed with real data allowed the development of a new set of patterns used to analyze well performance in Buracica and Balsamo oil fields. These tests showed good results when compared with the ones obtained from empirical patterns only. In addition, this approach allowed to immediately increasing the pattern number from two to a set of eight, improving the sucker-rod pumped wells analysis and management.
Reserves Growth: Enigma, Expectation or Fact?
Authors: Beliveau Dennis , Baker Richard
Published: December 2007

The phenomenon of "reserve growth" in established fields has been discussed by several authors, and described as a surprise or even an "enigma". This study uses the Alberta Energy and Utilities Board (EUB) historical reserve database to show the evolution of proved reserves versus time for oil pools in the Western Canadian Sedimentary Basin (WCSB), and demonstrates the consistent, long-term growth in reserves associated with the majority of these pools. The advantage of looking back at the performance of these fields is that many of them are very mature, so actual cumulative recovery levels are now very close to the estimates of expected ultimate recovery. We discuss the regulatory, business and technical reasons for these reserve changes and growth trends. Thoughts about the future growth potential of these reservoirs are also presented.
Irreducible Uncertainty — A Fact of Life in Reserve Estimates
Authors: Wright John D.
Published: December 2007

It is commonly assumed that more production data will lead to "bettef' estimates of remaining reserves. This is not necessarily correct. This paper reviews several real-world examples that disprove this hypothesis. Examination of reserve estimates on the same fields over several years demonstrates there is always a significant amount of irreducible uncertainty associated with reserve forecasts - even for proved developed producing properties. Furthermore, the percentage error in remaining reserves is still significant after many years of production.
Applied Reservoir Management Principles with Case Histories
Authors: Ezekwe John N.
Published: December 2007

Applications of technically sound reservoir management strategies to new and old reservoirs are important for maximum economic recoveries. Correct identifications of key geologic features, rock properties, state of reservoir fluids and major recovery mechanisms determine applicable reservoir management strategies. The critical decisions are selections of strategies that consider all available data and incorporate current technologies. The management strategies applied must be economic, conserve reservoir energy and adaptable to emerging technologies. Five reservoir management principles are presented as guides for determination and implementation of reservoir management strategies. The reservoir management principles are:

Conservation of reservoir energy Early implementation of simple strategiesSustained and systematic collection of dataContinuous application of improved recovery technologiesLong term retention of staff in multi-disciplinary teams

Case histories of 26R Reservoir, MBB/W31S Reservoirs, Luling and Slick Reservoirs are reviewed to illustrate the applications of the five reservoir management principles. The main objective of the report is to demonstrate through case histories that applications of the five reservoir management principles lead to technically sound reservoir management strategies that lead to maximum economic recoveries.
Developing Sub-Sea Cuttings Re-Injection Technology for Application in the Caspian Sea
Authors: Maggiori David , Reith Charlie
Published: December 2007

Over the past 5 years there has been a dramatic increase in the profile of BP's business activities in Azerbaijan. The Chirag Early Oil Project is delivering around 130,000 bbls / day and is in the middle of an extended reach drilling program.

Phase 1 of the ACG (Azeri, Chirag, Guneshli) Full Field Development (FFD) was sanctioned in 3Q 2001 giving the green light to detailed engineering for a 48 well platform with 9 pre-drill wells planned to commence through a template in March 2002. These wells will be suspended and tied back to a platform in 2004 for early oil production.

The Dada Gorgud Semi-submersible was contracted to drill these wells with zero discharge. BP and its partners decided to develop a dedicated Sub-sea Cuttings Re-injection System to dispose of drilled waste during this campaign.

This paper describes the process of Sub-sea CRI system development, focusing in on key areas of technology development such as corrosion/erosion resistance, horizontal tree design, new sub-sea interface technology and the surface cuttings processing system. General discussions around Project Management, Sub-surface and well design, will attempt to describe to the reader some of the challenges faced throughout this project.
CO2 Sequestration Potential of Texas Low-Rank Coals
Authors: Garduño Jorge Luis , Morand Henri , Saugier Luke , Ayers W.B , McVay Duane A.
Published: December 2007

Fossil fuel consumption is a primary source of CO2, a major greenhouse gas. Geologic methods, such as injection and sequestration of CO2 in coals may offer viable methods of reducing CO2 atmospheric emissions, while providing the added benefit of enhanced coalbed methane recovery.

The potential for CO2 sequestration in low-rank coals is unknown, and it differs significantly from bituminous coals. To evaluate the feasibility and the environmental, technical, and economic impacts of CO2 sequestration in Texas low-rank coal beds, we are conducting a 2-year study to characterize the coals located near major electrical power plants. We have identified potential of CO2 sequestration sites in coals near 3 Texas power plants. These 3 power plants discharge 34,068,751 short tons of CO2 annually, accounting for 14.6 % of Texas' point-source emissions.

On the basis of preliminary modeling of one site, using assumed permeability, CO2 storage and methane content values, we conclude that 360 wells on 80-acre spacing could sequester CO2 emissions for the Gibbons Creek plant for 11 years, while producing 90 Bcf of coalbed methane. However, reservoir properties are poorly known and, thus, the volumes of CO2 that may be sequestered and the amount of methane that may be produced are speculative at present. Future study will focus on better reservoir characterization and additional modeling.
Feeling the Pulse of Drill Cuttings Injection Wells – A Case Study of Simulation, Monitoring and Verification in Alaska
Authors: Guo Quanxin , Abou-Sayed Ahmed S. , Engel Harold R.
Published: December 2007

In April 1998, a program for continuous deep disposal of drill cuttings and open pit materials was initiated on the North Slope of Alaska. This ongoing injection project is commonly referred to as GNI, standing for Grind and Inject. Accumulated drilling cuttings and mud slurry is injected into a receptive cretaceous soft sandstone in three wells, GNI-1, GNI-2, and GNI-3. Typical operations involve injecting slurry into one of the three wells continuously for a number of days and then switching injection to another well. The average injection rate is approximately 30,000 barrels per day. As of September 30, 2002, project injection has included 12.7×106 barrels of water, 30.9×106 barrels of slurry containing 2.0×106 tons or 2.2×106 cubic yards of excavated frozen reserve pit material and drilling solids and 1.31×106 barrels of fluid from ongoing drilling operations.

Knowledge of the fate of the drilling and open pit materials during injection is paramount to assure the safe sequestration of the materials without harm to the environment. Numerical modeling, well testing (including step rate and pressure falloff testing) as well as logging surveys were performed periodically to assess the disposal wells' operational integrity and to ensure the safe containment of the disposed waste slurry. The great capacity of these injectors highlighted the mechanisms for slurry being accepted by multiple and branched fractures - part of the slurry went to previous fractures during subsequent batch injections. The current paper will emphasize on how to integrate numerical simulations, well testing/monitoring and operational data to estimate storage capacity and to construct a clear representation of what was happening underground during this grind and injection operation. The work has implications on other large drilling waste injection projects worldwide.
Horizontal Openhole Gravel Packing with Reactive Shale Present—A Nigeria Case History
Authors: Dickerson Rick C. , Ojo-Aromokudu O. , Bodunrin Abiodun A. , Passant Kip , Roane Tom , Penno Andrew , Fitzpatrick Harvey
Published: December 2007

An operator company and service company have used concentric alternative flowpath technology to successfully gravel pack five horizontal openhole completions where reactive shales have caused problems in the past. These horizontal openhole gravel packs were the first for the Nigeria operator company, and were the service company's first use of this concentric alternative flowpath system in a horizontal openhole completion.

This paper discusses operational procedures, best practices, and lessons learned during the completion of these wells. Early attempts to manage sand production with predrilled liners had failed, and subsequent attempts to control sand with stand alone screens had also failed. Using a gravel pack was another alternative sand control method, but the presence of reactive shales, a known problem in the field, had to be addressed. Concentric alternative flowpath technology has effectively controlled reactive shales and gravel packed five wells in this field. In these cases, an engineered predrilled outer shroud was installed for hole cleanup and displacement before running the screen and gravel packing. The key factors in successfully completing these wells that will be discussed in detail include: Improved drill-in fluid designs and effective casing cleanup and displacement methodsOpenhole and casing cleaning and preparation prior to running the outer shroud and screenOuter shroud and screen installation processGravel packing method and procedure
Gas Lift Automation: Real Time Data to Desktop for Optimizing an Offshore GOM Platform
Authors: Reeves Donald , Harvey Ronald , Smith Troy
Published: December 2007

Gas lift optimization is fundamental to protecting base production in oil fields worldwide. With real-time wellhead surveillance and automation data available on a portable laptop computer, the engineer can quickly identify well problems and opportunities to improve gas lift performance. A continuous gas lift automation and wellhead surveillance system was installed on the Amberjack field in the Gulf of Mexico and realized a 7% increase in production.

This paper will discuss the problems engineers experienced understanding daily production variance before automation was installed, the system functionality of the automation system, and the results of increasing base production by 7%. Project execution is also discussed because of its importance in ensuring the offshore personnel were engaged with the project.
Maximizing Rig Automation Safety and Efficiency with Remote Monitoring and Management
Authors: Levett Bryce , Suvans Lance
Published: December 2007

The goal of rig automation has always been to improve safety and efficiency during drilling operations. Repetitive operations can be carried out by equipment designed to reduce manpower/human interaction. Interaction between rig personnel and equipment has changed as more areas of the drilling rig have become automated. In order to make this interaction more seamless a system has been developed comprised of remote monitoring, diagnostics and technical support. Case histories of rig equipment operations have shown that use of this remote monitoring and management system reduces downtimes, increases safety and enhances maintenance. The system expands the focus of rig automation and moves rig-automation technology into a new realm. The future of drilling operations, spares planning and equipment development can be changed from a reactive mode into a proactive mode, giving drilling contractors and operators a much needed advantage.
Stochastic Approach to Kick Tolerance Determination in Risk Based Designs
Authors: Dedenuola Adetola. D. , Iyamu Isaac. E , Adeleye Olayinka. A.
Published: December 2007

Drilling experience in the Niger Delta has shown that inappropriate selection of kick tolerance could constitute a serious setback to the implementation of cost effective and innovative solutions in well designs. While a conservative selection of kick tolerance could make a well design uneconomical, attracting severe cost penalties by fostering use of expensive / extreme pressure-ratings BOPs and extra casing strings sometimes, undue tightening of the tolerance on the other hand could make a well undrillable from safety point of view. This consideration poses serious dilemma to the well engineer who must balance the demands of conflicting alternatives in his management of design risks. To resolve this, the approach of stochastic analysis procedures to the prediction of appropriate design kick tolerance in any given geological setting and operational environment is being presented in this paper. Since this approach depends largely on the use of historical kick records, certain concerns regarding the reliability and acceptability of the use of historical data for the purpose of kick tolerance modeling and selection were equally addressed. Finally, a well example shows how this method has been used to integrate kick tolerance considerations in the management of design risks associated with the deployment of new technology application, expandable sand screen, in a high rate horizontal oil producer.
Study of the Effects of Pressure and Temperature on the Rheology of Drilling Foams and Frictional Pressure Losses
Authors: Lourenço Affonso M. F. , Miska Stefan Z. , Reed Troy D. , Pickell Mark B. , Takach Nicholas E.
Published: December 2007

A discussion about horizontal foam flow behavior in pipes and annular geometry under elevated pressures and temperatures is presented. The study is empirically based and covers the effects of foam quality, foam texture, pressure, temperature and geometry of the conduit on the rheological response of foams.
An Improved Model to Predict Reservoir Characteristics During Underbalanced Drilling
Authors: Biswas D. , Suryanarayana P. V. , Frink P. J. , Rahman S.
Published: December 2007

We present an algorithm and an approach for the coupling of a 2-phase, 2-dimensional transient reservoir simulator using a control volume finite element approach, and a 2-phase transient mechanistic multiphase wellbore flow model to dynamically characterize reservoirs while drilling underbalanced. This approach succeeds in accounting for storage effects in both the wellbore and reservoir. The coupling is achieved at the wellbore flowing pressure for given injection parameter and back pressure time functions, and the inverse problem is posed as one of minimizing the difference between predicted and observed return parameter time functions. A genetic algorithm (GA) approach, coupled with a one dimensional search scheme is used to achieve optimization. This paper focuses on one aspect of dynamic reservoir characterization-the prediction of permeability as a function of drill depth. Permeability results are obtained for an example problem and the accuracy and limitations of the proposed approach are discussed. Numerical problems in dealing with the grossly different time scales of reservoir and wellbore behavior, and practical limitations of reservoir characterization during underbalanced drilling are described. Improvements to the algorithm and future work are also discussed.
HP/HT Rheology Of Aqueous Compressible Fluids For Underbalanced Drilling And Effect Of Formation Fluids Contamination
Authors: Kakadjian Sarkis , Herzhaft Benjamin , Neau Laurent
Published: December 2007

When drilling underbalanced, the pressure of the drilling fluid is maintained at a value below the formation pressure. In order to lower well pressure, specific low density fluids are needed i.e. gas, aerated mud or foam. Foam is particularly beneficial for drilling mainly due to its low density coupled with good carrying capability, but its use remains hazardous due to the incomplete knowledge of its bottom-hole properties and especially of its flowing properties. Predicting the pressure drop while drilling with a compressible fluid is not an easy task and for this purpose, knowledge of its rheological properties is of primary importance. Moreover, drilling underbalanced implies continuous contamination of the foam with formation fluids (brines or crude oils), and it is of great importance to characterize the impact of these contaminants on the dynamic behavior of the compressible fluids.

This study is part of a research program conducted in order to improve the knowledge on aqueous aerated fluid and foam properties for drilling. A specific HP/HT rheometer has been built which is able to measure rheological properties of compressible fluids under pressure (up to 50 bars ) and temperature (up to 90 °C ) conditions. A Re-circulating set up allows to circulate the foam at a specific shear rate condition until the structure (and the resultant shear stress) is equilibrated. A visualization cell coupled to an image acquisition device permits to characterize the structure of the foam in parallel to the rheological measurement.

A titanium contamination syringe pump which can handle up to 500 cc in one shut of electrolyte solution, crude oil or any other contaminants is set in order to contaminate the aerated and foamed fluid once generated in a recirculating volume of approximately 950 cc.

Experiments were performed with a specific foaming system already used on site for drilling application. Rheological evaluations at several pressures, temperatures and fluid qualities were investigated. Interpretations of the data incorporating the importance of foam structure are proposed to help building a coherent model. There are presented for the first time results of the effect of contaminants such as electrolyte solutions and crude oil under dynamic conditions, over the stability and rheological properties of aerated fluid and foams at high pressure and high temperature conditions, such as can be observed during underbalanced drilling applications when occurring inflows of such contaminants.

These measurements allow a better understanding of the compressible fluid dynamic properties under bottom-hole conditions including contamination from formation fluids.
Increasing Computational Speed of Flash Calculations with Applications for Compositional, Transient Simulations
Authors: Rasmussen Claus P. , Krejbjerg Kristian , Michelsen Michael L. , Bjurstram Kersti E.
Published: December 2007

Approaches to reducing the computation time spent on flash calculations in compositional, transient simulations are presented. In a conventional flash calculation the majority of the simulation time is spent on stability analysis even for systems far into the single phase region. A criterion has been implemented for deciding when it is justified to skip the stability analysis. With the implementation of the developed time saving initiatives, it has been shown for a number of compositional, transient pipeline simulations, that it is possible to reduce computation time spent on flash calculations by between approximately 85-90%.
Experimental Study of Gas Injection in Surfactant-Alternating-Gas Foam Process
Authors: Xu Q. , Rossen W. R.
Published: December 2007

Fractional-flow methods have been shown to be accurate and successful in modeling surfactant-alternating-gas (SAG) foam processes. Fractional-flow theory indicates that the success of SAG processes depends on steady-state foam behavior at very low liquid fractional flow fw (very high foam quality). Previous simulation studies of these processes have relied on extrapolating steady-state data taken at much higher values of fw. Radically different results are predicted depending on how these extrapolations are made. Data are needed at very low fw to predict SAG performance in the field.

Experimental fractional-flow curves are presented for two surfactant formulations in Berea sandstone core, with no oil present, at extremely high foam quality. Results are then scaled-up using fractional-flow theory to a hypothetical field-scale application. In all cases the data scale-up to successful mobility control on the field scale. In one case, foam suffered an abrupt decline from stronger foam to coarser foam with increasing foam quality, with a multi-valued fractional-flow function, in agreement with some earlier experimental and theoretical results.

In this study, average water saturation in the core was determined by weighing the core continuously during the experiment. Advantages and limitations of the technique are discussed.
Prediction of Oil Production by Gravity Drainage
Authors: Li Kewen , Horne Roland N.
Published: December 2007

Mathematical models to predict oil production accurately by gravity drainage have been few. To this end, an analytical model was developed to determine the ultimate oil recovery by free-fall gravity drainage. An empirical oil recovery model was proposed accordingly to match and predict oil production. The model was tested against experimental, numerical, and field data of oil production by free-fall gravity drainage. The results demonstrated that the oil recovery model could work satisfactorily in the oil-gas cases studied. Initial oil production rate, entry capillary pressure, and average residual oil saturation can be estimated using the oil recovery model. An approach was also developed to infer capillary pressure curves from the oil production data by free-fall gravity drainage.
Simulating the Impact of Faults on CO2 Sequestration and Enhanced Oil Recovery in Sandstone Aquifers
Authors: Pasala S. M. , Forster C. B. , Lim S. J. , Deo M. D
Published: December 2007

Outcrop-based studies of faults, combined with in situ and laboratory testing, can yield quantitative maps of the detailed geometry of permeability and porosity heterogeneity in fault-affected rocks. Yet we often don't know which aspects of the detailed structures mapped by geoscientists must be preserved when reservoir engineers assign material properties in production-scale reservoir simulators. Furthermore, we lack practical approaches for upscaling the effects of the detailed features that must be preserved. We shed light on these issues by comparing, through simulation at an unusually detailed scale, the impact of fault permeability/porosity structures on enhanced oil recovery processes that involve carbon dioxide (CO2) flooding. Injecting CO2 into a reservoir with fault-derived heterogeneity leads to more complicated fluid interactions that depend on whether the faults act as barriers, conduits or combined barrier-conduits. These fault-scale interactions can play an important role in determining ultimate recovery of oil from the reservoir. The ECLIPSE™ reservoir simulator is used to explore how different, 3-D, fault-related permeability/porosity structures might impact oil recovery. The results of these studies are incorporated in interwell-scale numerical simulations of CO2 injection and migration in order to assess the implications of incorrectly assessing the fluid flow properties of faults in sandstone aquifers. Sandstone permeability values range from 10s to 1000s of mD. Deformation bands can reduce the effective permeability of faulted sandstone by one or more orders of magnitude while fractures can locally enhance the effective permeability of the host sandstone by similar magnitudes. Simulator output shows how fault conduits and barriers can restrict migration of CO2 through the aquifer as a consequence of bypassing (conduits) or compartmentalization (barriers). The simulation results reveal how the geoscientists' ability to quantify and discriminate between high-permeability vs. low-permeability faults in sandstone reservoirs can play an important role in designing enhanced oil recovery and CO2 sequestration operations.
Well Placement Optimization in Field Development
Authors: Badru O. , Kabir C. S.
Published: December 2007

Determination of optimal well locations is a challenging task because engineering and geologic variables affecting reservoir performance are uncertain and they are often correlated in a nonlinear fashion. This study presents an approach where a hybrid optimization technique based on genetic algorithm, with polytope algorithm as the helper method, was used in determining optimal well locations. The Hybrid Genetic Algorithm (HGA) has been shown to work on synthetic and field examples alike. The HGA was used to optimize both horizontal and vertical wells for both a gas injection and water injection projects with net present value (NPV) maximization as the objective.

Comparison of results was made between locations proposed by the HGA and those selected by engineering judgment. Results showed that horizontal wells performed better than vertical wells from the recovery standpoint for the synthetic reservoir. For a real reservoir, however, horizontal wells performed only marginally better than the vertical wells owing to low-kv/kh ratio. We also observed that optimal well locations are a strong function of the anticipated project life.

A method of integrating the HGA with Experimental Design (ED) was also investigated. For this purpose, a synthetic reservoir was used and exhaustive runs were made with increasing well count. In this particular case study, we observed that the uncertainties in the variables affecting recovery did not affect the optimal number of wells required to develop this reservoir. Thus, forehand knowledge of the well count eliminates the need for the inclusion of this process variable in the ED matrix.
Smart Waterflooding Tight Fractured Reservoirs Using Inflow Control Valves
Authors: Arenas Eliana , Dolle Norbert
Published: December 2007

Pressure cycling is a technique that makes use of smart well technology to optimize waterfloods in tight fractured reservoirs with horizontal wells. It is an adaptation of another technique known as pressure pulsing, which involves cycling an entire injection well. In pressure cycling, selected intervals of the well are cycled rather than the entire well. By controlling water injection across these intervals, it is possible to prevent water shortcutting between producer-injector pairs due to fractures, thus greatly improving the probability of success of the waterflood. During pressure cycling, an optimized balance is reached between periods of injection into the fractured zone and periods of injection into only the matrix. This optimized balance results in an increase in cumulative oil production over other solutions like chemical or mechanical fracture shut-off in tight fractured reservoirs.

In pressure cycling, inflow control valves (isolated with packers) are placed in a horizontal injector across from fractured zones. The horizontal producer belonging to the well pair is left as it is, with a conventional completion.

During waterflooding operations, water cut is measured in the producer. Based on the water cut measurement in the producer, valves in the injector are either opened or closed, taking care to maximize oil production, minimize water production, and maintain reservoir pressure. The cycling technique repeats over the years, though progressively becoming less efficient as the matrix around the fractures becomes more saturated with water.

In this study, pressure cycling was tested via reservoir simulation on a 2D generic model. The model included a tight homogenous matrix (5 mD) and three thin explicit fractures (width of 1 cm each). Both the production and injection wells were completed in the oil leg of the reservoir. The fractures were assumed to be extensive enough to span the two horizontal wells, but not extensive enough to intersect the aquifer. The simulation results from the model help identify two factors which greatly influence the pressure cycling technique. These are: (1) the fractured zone injectivity, and (2) the matrix injectivity. In fact, the ratio of the fractured zone to matrix injectivity is the key in determining the applicability of pressure cycling. It can be concluded that: When the injectivity ratio increases, i.e. for lower matrix injectivities and/or higher fracture density, the scope for pressure cycling increases significantly.
A Stochastic Approach to Extract Vapex Related Dispersion Coefficients from Magnetic Resonance Images
Authors: Karmaker Kulada , Maini Brij B.
Published: December 2007

In vapor extraction (Vapex) process, the dispersional mixing between injected solvent vapor (propane) and in-situ bitumen occurs along the oil-solvent interface during the oil drainage process. The solvent dispersion coefficient is a key parameter that governs the oil dilution efficiency as well as the rate of production. To predict the field performance of the Vapex process it is vital to accurately estimate the value of the dispersion coefficient at the field conditions of interest. Currently, there are no factual data available in the literature and there is no proven empirical methodology for estimating the dispersion coefficients that would be pertinent to the Vapex process.

Recently, the Magnetic Resonance Imaging (MRI) tools have been used to gain insights into the Vapex process. The MRI technique can generate 2-dimensional (2-D) images during the progress of a laboratory-scale Vapex experiment. Both the original bitumen and the solvent vapor are virtually invisible in these MRI generated 2-D images. However, the propane saturated bitumen is clearly visible and in the diluted oil zone, the signal intensity is a function of the dissolved solvent concentration.

This paper describes a new technique to extract the net dispersion coefficients pertinent to the Vapex process from 2D MRI images captured during a test. A new mathematical model has been developed for analyzing such 2-D images. The model portrays the unique context of mass transfer mechanisms and the interface propagation in the Vapex process. The technique has been used on a previously published MRI image and found to be very effective and straightforward.
A New Method for Measuring Solvent Diffusivity in Heavy Oil by Dynamic Pendant Drop Shape Analysis (DPDSA)
Authors: Yang Chaodong , Gu Yongan
Published: December 2007

This paper presents a new experimental method and its computational scheme for measuring the diffusion coefficient of solvent in heavy oil under the practical reservoir conditions by dynamic pendant drop shape analysis (DPDSA). In the experiment, a see-through windowed high-pressure cell is filled with the test solvent at desired pressure and temperature. Then a heavy oil sample is introduced slowly through a syringe delivery system to form a pendant drop inside the pressure cell. The subsequent diffusion process of solvent into the pendant oil drop causes its shape and volume to change until an equilibrium state is reached. The sequential digital images of the dynamic pendant drop are acquired and digitized by applying computer-aided digital image processing techniques. Physically, variations of the shape and volume of the pendant drop are attributed to the interfacial tension reduction and the well-known oil swelling effect as solvent gradually dissolves into heavy oil. Theoretically, the dynamic pendant drop profile is governed by the Laplace equation of capillarity and the molecular diffusion process of solvent into the pendant oil drop is described by the mass diffusion equation. An objective function is constructed to express the discrepancy between the experimentally observed and the numerically predicted profiles of the dynamic pendant drop. The solvent diffusivity in heavy oil and the mass-transfer Biot number are used as adjustable parameters and thus determined once the minimum objective function is achieved. This novel experimental technique is tested to measure diffusivities of carbon dioxide in a brine sample and carbon dioxide in a heavy oil sample, respectively. It should be noted that, with the present technique, a single diffusivity measurement can be completed within an hour and only a small amount of oil sample is required. The interface mass-transfer coefficient at the solvent-heavy oil interface can also be determined. In particular, this new technique allows the measurement of solvent diffusivity in an oil sample at constant pre-specified high pressure and temperature. Therefore, it is especially suitable for studying the mass transfer process of injected solvent into heavy oil during solvent-based post-cold heavy oil production (CHOP).
Using Cross Dipole Sonic Anistropy Data to Improve Reservoir Understanding in the Southern/Marine Areas of Mexico
Authors: Aquila Fredy Jimenez , Carmen Ciudad del , Barajas Jose Sanchez , Mesa Harold , Herrera Ricardo Rodriguez , Kessler Calvin
Published: December 2007

Crossed dipole sonic logging data has been used to improve reservoir understanding in the Southern/Marine areas of Mexico. The anisotropy analysis of the in-line and cross-line dipole waveform data provides the fast and slow shear wave travel time data and their corresponding orientation. These slowness values provide the input to a model that calculates the minimum and maximum principal stresses and the far-field stress orientation. The far-field stress orientation and stress anisotropy combined with 3D hydraulic fracture modeling is used to optimize the stimulation treatment design. The far-field stress information is also used for optimizing the perforated interval and orientation of the perforations.

Natural fractures provide many challenges for drilling, zonal isolation, and production enhancement. The detection and orientation of natural fractures is a needed key for reservoir management, and can be determined from the cross dipole anisotropy analysis. Inflow analysis from production logs has verified that the fractures identified by anisotropy analysis are open and are a major source of production in the Cretaceous section in the Marine area and Cretaceous/Jurassic in the Southern area. Mapping of the fracture orientation obtained from the sonic anisotropy analysis is used for well planning. Crossed dipole log examples in carbonate formations in Mexico will be used to illustrate how reservoir understanding can be improved with the use of this interpretation process.
Correlations of Shear vs. Compressional in Shaly Sands and Application to Quicklook Hydrocarbon Detection
Authors: Chardac O. , Brie A. , Chouker A. C.
Published: December 2007

Since the introduction of the dipole shear sonic measurements a large number of compressional and shear data sets have been acquired, especially in shaly sands. Correlations between these measurements are now well established and used routinely. The Castagna mudrock and sandstone lines on the Vp and Vs crossplot are popular among geophysicists while trends of Vp/Vs versus Δt proposed by Brie et al. (1995) are popular among petrophysicists. As expected, a comparison of these correlations shows that they are quite similar in saturated and dry conditions. However, the Vp/Vs trends can simulate different pore fluid types or saturation conditions because the fluid effect is accounted for through the Gassmann equation.

Using published correlations for adiabatic elastic moduli with temperature and pressure, we have generated slowness charts for water solutions and hydrocarbons and used them to refine the Vp/Vs trends. In particular we generated different trends for sands impregnated with fresh water, salt-saturated water and live oil. We show that the Vp/Vs trend for live oil is quite distinct from that in water.

An application of these correlations is to convert shear to compressional. As shear slowness is little sensitive to fluid type, the obtained compressional slowness, Δtwet, simulates water-filled shaly sands. A comparison of Δtwet with measured Δt provides a quicklook indicator of hydrocarbons. Various examples are presented and discussed. We show that all correlations give good results in sands with porosity larger than 20%. Between 10 and 20% porosity, correlations must be adjusted to obtain reliable results. Below 10% porosity, the technique becomes unusable.

The Δtwet estimate has other interesting applications in the domain of rock mechanics and stress evaluation because it is unaffected by fluid content. An example shows how the technique was applied to improve hydraulic-fracture design.
Determination of Primary and Secondary Porosity in Carbonate Formations Using Acoustic Data
Authors: Kazatchenko Elena , Markov Mikhail , Mousatov Aleksandr
Published: December 2007

A technique for quantitative estimation of crack or vug porosity using acoustic well-log data is proposed. The estimation is based on a double-porosity rock model that consists of a solid matrix with primary porosity and inclusions which represent the secondary pore system. We applied the method of effective medium approximation (EMA) to calculate P- and S-wave velocities in the double-porosity formations. This method allows modeling multicomponent systems composed by grains of different mineral components, primary pores and secondary inclusions. All these components are approximated by spheroids with different aspect ratios.

The technique includes two steps. At the first step the matrix P- and S-wave velocities as functions of the primary porosity are calculated. For this procedure two groups of parameters are required: 1 - solid-skeleton elastic moduli that are defined by laboratory measurements or calculated using formation mineralogical composition; 2 - aspect ratios for grains and primary pores. We determined these aspect ratios by the inversion of the published regression equations for P- and S-wave velocities to the microstructure parameters.

At the second step, using the obtained previously matrix parameters, the value and aspect ratio of secondary pores are determined by the joint inversion of P- and S-velocities (minimizing the difference between the experimental data and velocities predicted for the double-porosity model). The obtained aspect ratio indicates the type of secondary-pore system (cracks or vugs).

Examples of secondary-porosity determination using acoustic core and well log data are presented.
Completion Optimization in the Wamsutter Field, SW Wyoming
Authors: Heidt J. H. , Harting T. A. , Glover M. D. , Rowe W. , Adegbola K. A. , Rucker L. R.
Published: December 2007

This paper describes the successful application of a rigorous optimization process to new well completions in the Wamsutter area of SW Wyoming. High well costs and relatively low netback product prices require that all new well completions be rigorously optimized for maximum value. Excellence in stimulation design, execution, and evaluation is absolutely critical to economic success in this heterogeneous, stacked, tight formation gas play.

Flawless, Safe Execution is the most critical part of the completion process. QA/QC standards require rigorous prejob and day-of-job fluid and proppant testing, the ability of all chemical add pumps to accurately deliver specified rates, and rigorous material balance tracking throughout the job. The job must not be pumped if all personnel, equipment, and materials are not fully prepared and up to spec.

Rigorous Engineering of completion designs is performed by a geographically dispersed, multi-disciplinary team, using petrophysical, reservoir, and frac design models to assure the most optimum design based on all available data and knowledge. The petrophysical model uses standard log data to estimate reservoir properties and mechanical rock properties. Log data is seamlessly converted into layer data for input into frac and reservoir models. Designs are optimized for each well based on predicted fracture characteristics and reservoir performance. Data is exchanged via a secure interactive web-based system. Data flow and work processes are well mapped and highly efficient.

Systematic Learning is pursued through comprehensive postcompletion well reviews. Frac design and reservoir models are re-run on every completion to help explain actual well performance versus pre-completion estimates. Production logs and frac diagnostic data also aid in understanding well results. The petrophysical, fracture stimulation, and reservoir models are periodically updated to incorporate learnings. Precompletion predictability has improved substantially.

The application of this model on 99 wells completed in 2002 has resulted in a 20% improvement in production and estimated ultimate recovery. Additionally, drilling costs have been reduced by 5%. Cost per unit gas volume produced has improved by 27%. Continued improvement in reservoir predictability will allow better optimization of top-quartile wells by focusing strongly on frac length and conductivity optimization, and of lower-quartile wells by minimizing the completion to only those few contributing sands.
Modeling Fracture Tip Screenout and Application for Fracture Height Growth Control
Authors: Bai M. , Morales R. H. , Suarez-Rivera R. , Norman W. D. , Green S.
Published: December 2007

This paper discusses the use of numerical simulations for predicting the onset and development of fracture tip screenout (TSO). It presents a parametric study for fracture containment to prevent height growth into water boundaries or a gas cap, under conditions that approximately simulate Gulf of Mexico reservoirs (weakly consolidated, high permeability soft formations). Different typical field cases were analyzed to demonstrate height containment at TSO conditions. The perforation interval is critical to height containment, with perforation height of only a fraction of the total pay interval required in some cases in order to create TSO.