bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

AbstractIn 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Summary
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.