bluuebunny/crossref_metadata_2025_split huggingface dataset:
Feasibility Study of the Stability of Openhole Multilaterals, Cook Inlet, Alaska
Authors: Moos D. , Zoback M. D. , Bailey L. 
Published: December 2007

SummaryA study of in-situ stress, rock strength, and wellbore stability was initiated in the Hemlock sands of the McArthur River field, Cook Inlet, Alaska, to evaluate the potential of leaving the near-wellbore portions of multilaterals uncased. A northwest/southeast direction of maximum compression and a strike-slip faulting regime were predicted from analyses of leakoff test data and observations of failure (breakouts) in adjacent wells. Caliper, well-log, and core data indicated that cementation, and hence rock strength, is highly variable within the reservoir. Thus, it was decided to evaluate the stability of the lateral sections (i.e., the likelihood of wellbore failure during production) as a function of both stratigraphic position and well orientation. Laboratory rock-strength measurements were carried out on cores selected from target intervals in adjacent wells to provide sufficient precision to quantify the results. The results indicated that, while some reservoir intervals have high enough strengths to be left uncased when drilled in the most stable direction, these intervals are too thin to provide sufficient support at the point where the laterals leave the parent well. This justified the decision to case back the laterals to the parent well despite the cost.
Orienting Live Well Perforating Technique Provides Innovative Sand-Control Method in the North Sea
Authors: Eriksen Jan Hilding , Sanfilippo Francesco , Kvamsdal Arne L. , Flint George , Kleppa Erling 
Published: December 2007

SummaryThe Varg field is a development in the North Sea operated first by Saga Petroleum and currently by Norsk Hydro. It consists of a not-normally-manned wellhead platform (WHP) with dry wellheads and a floating production storage offloading (FPSO) vessel for processing the crude. The reservoir is heterogeneous sandstone of Upper Jurassic age, with estimated reserves of approximately 35 million STB.During development planning of the field, it was felt that sand production was likely to occur, and this phenomenon was actually experienced during well testing. Because this development was considered to be a marginal field, an extensive program was initiated to review and select a technical completion solution that would minimize the risk of sand production so that production potentials could be maximized. This paper discusses how a unique perforating solution was developed to provide the controls needed to manage the potential for sand production.The first part of this paper summarizes (1) the drainage strategy, and the implications of that strategy on selecting the perforation intervals, and (2) the results of a rock mechanics study that focused on the conditions critical for the onset of sand production, as well as recommendations for minimizing the risk. The primary recommendations were to avoid perforation of the weakest intervals and to shoot perforations that would be oriented parallel to the maximum horizontal stress.The second part of the paper describes how successful oriented perforating was achieved in these wells. The primary completion challenges included the following:Development of a slickline system that could perforate the entire zone simultaneously in a given direction in a vertical well. A means to remove the perforating guns from the well without having to kill it after completion of the perforation, as there was insufficient rathole to leave the guns in the hole.An oriented modular perforating system was developed so that these conditions could be achieved. The requirements were met by installing a gun anchor in the well before the completion was installed. Then, the orientation of an orienting lug was measured with a gyro, and, based on the data from the survey, the guns were aligned in the correct orientation. Subsequently, gun sections of length maximized to available lubricator length were run on slickline. The gun section aligned itself automatically to the measured orientation of the orienting lug because of the equipment design. Currently, three wells have been perforated using this system. All of them are sand-free since startup 1½ years ago.
Evaluation of the Steam-Injection Process in Light-Oil Reservoirs
Authors: Dehghani Kaveh , Ehrlich Robert 
Published: December 2007

SummaryFeasibility of steam injection for three light-oil reservoirs in different geologic settings has been evaluated. The settings studied were a waterflooded deltaic sandstone, a waterflooded vuggy dolomite, and a deltaic sandstone structural trap with a gas cap. Optimization of steam injection to take advantage of individual reservoir characteristics is demonstrated.Results show that light-oil steamfloods can be designed to take advantage of post-secondary oil-saturation distribution. The resulting project may be carried out in a considerably different fashion from that of conventional heavy-oil steamfloods.We also re-evaluated an unsuccessful light-oil steamflood (LOSF) project carried out in the past. The re-evaluation correctly predicted failure because of early steam breakthrough. The results show that by considering details of geology and displacement process physics, the recent advances in reservoir characterization and modeling tools enable us to predict the performance of these projects more accurately.
How To Manage Drill-In Fluid Composition To Minimize Fluid Losses During Drilling Operations
Authors: Cobianco S. , Bartosek M. , Lezzi A. , Guameri A. 
Published: December 2007

SummarySelection of the best drill-in fluid for drilling horizontal wells is essentially based on the characteristics of the filter cake formed in the near-wellbore region. Minimizing filtrate loss into the formation by forming a thin filter cake with low porosity and permeability is the key to managing formation damage problems.In this paper, the effects of drill-in fluid components and their interactions in the formation of a filter cake, which provides an effective caking process with reduced filtrate loss, have been evaluated. Statistically designed experiments carried out with a dynamic filter press apparatus were used to identify which variables had the most significant effect on filtrate loss and cake permeability so that the optimum fluid composition could be determined. These variables include the formation characteristics (permeability and pressure values) as well as the type and amount of the fluid components.Data obtained in this experimental design study were analyzed with the multiple-linear-regression method, which allowed us to model the filtrate loss and cake permeability. The analysis showed that the most important factors are the type and the concentration of the polymer. In particular, when the formation temperature is as high as 90°C, we can reduce the cake permeability and the filtrate loss by increasing the concentration of scleroglucan. An interaction effect between the concentration of scleroglucan and the more highly crosslinked starch was also identified, and none of the other variables showed any significant effects within the range of experimentation. This fact can be considered as an advantage because it allows flexibility in the choice of other factors when appropriate for the cost reduction.
Impact of Reservoir Mixing on Recovery in Enriched-Gas Drives Above the Minimum Miscibility Enrichment
Authors: Solano R. , Johns R. T. , Lake L. W. 
Published: December 2007

SummaryGas enrichment is an important variable used to optimize oil recovery in enriched-gas drives. For slimtube experiments, oil recoveries do not increase significantly with enrichments greater than the minimum miscibility enrichment (MME). For field projects, however, the optimum enrichment required to maximize recovery on a pattern scale may be different from the MME. The optimum enrichment is likely the result of greater mixing in reservoirs than in slimtubes. In addition, 2D effects, such as channeling, gravity tonguing, and crossflow, can impact the enrichment selected.Numerical simulation is often used to model the effect of physical mixing on oil recovery in miscible gasfloods. Unfortunately, numerical dispersion can cloud the interpretation of the results by artificially increasing the level of mixing in the reservoir.This paper investigates the interplay among various mixing mechanisms, enrichment levels, and numerical dispersion. The mixing mechanisms examined are mechanical dispersion, gravity crossflow, and viscous crossflow. The U. of Texas Compositional Simulator (UTCOMP) is used to evaluate the effect of these mechanisms on recovery for different grid refinements, reservoir heterogeneities, injection boundary conditions, relative permeabilities, and numerical weighting methods, including higher-order methods. The reservoir fluid used for all simulations is a 12-component oil displaced by gases enriched above the MME.The results show that for 1D enriched gasfloods, the recovery difference between displacements above the MME and those at or near the MME increases significantly with dispersion. The trend, however, is not monotonic and shows a maximum at a dispersivity of approximately 4 ft. The trend is independent of relative permeabilities and gas trapping for dispersivities of less than approximately 4 ft. For 2D enriched gasfloods with slug injection, the difference in recovery generally increases as dispersion and crossflow increase. The magnitude of the recovery differences is less than that observed for the 1D displacements. Recovery differences for 2D models are highly dependent on relative permeabilities and gas trapping. For water alternating gas (WAG) injection, the differences in recovery increase slightly as dispersion decreases. That is, the recovery difference is significantly greater with WAG at low levels of dispersion than with slug injection. For the cases examined, the magnitude of recovery difference varies from approximately 1 to 8% of the original oil in place (OOIP).
Use of Color Movies for Interpretation and Presentation of Reservoir Simulation Results
Authors: Good P.A. , Rogers W.L. , Rester S. , Smith R.A. , Dodge L.P. 
Published: December 2007

Motion pictures made from color-coded spatial distributions for fluid saturations, phase compositions, pressure, and temperature are applied to the interpretation of reservoir simulations. The use of computer animation is described as applied to several enhanced oil-recovery processes. Additional insight into simulation results can increase markedly the potential value of numerical simulation.

Introduction
Use of mathematical reservoir simulators to correlate reservoir data and to predict the behavior of petroleum reservoir recovery processes has become an important part of modern reservoir engineering. In addition to the major technical difficulties inherent in developing and running these simulators, it has been found that it is frequently difficult and time consuming to interpret and present the results from simulators. One underlying cause of this difficulty of interpretation and presentation of simulator results is the quantity of information provided by simulators. For example, a typical compositional thermal simulation (three components) might employ five wells and 300 grid blocks. At each grid block, temperature, pressure, three saturations, and an additional composition are available at each time step. Well rates and pressures, perhaps at several different completion intervals, also are calculated. If the simulation takes 300 time steps to run to completion, more than 450,000 numbers will represent the "solution" to the particular reservoir engineering problem (approximately 1,350,000 intergrid block fluxes also would have been computed and used by the simulator during the simulation). As several dozen of these simulations might be made during a field study, it is clear that the simulator user can be faced with more information from the computer than can be assimilated or interpreted conveniently.A second source of difficulty is the inherent two- and three-dimensional aspects of many simulations. It is straightforward to represent graphically the dynamic history of one-dimensional quantities such as well rates as a function of time. Two-dimensional quantities, such as water saturation as a function of position in a vertical cross section, are more difficult to display on a graph. One commonly used display method for two-dimensional cross sections is line-printer contour plots (Fig. 1). While contour plots provide for a rapid visual evaluation of spatially distributed quantities, a distinct advantage over tables of numbers, these plots have several disadvantages.1. They have a low information content - i.e., a number of such plots would have to be viewed simultaneously to provide a picture of all the reservoir variables in a given cross section at one point in time.2. The spatial resolution and the contour resolution of the plots are low.3. It is generally difficult to gain an appreciation of reservoir dynamics from these static "snapshot-in-time" representations of reservoir conditions.
JPT
P. 1331＾
Selectively Placing Many Fractures in Openhole Horizontal Wells Improves Production
Authors: Love T. G. , McCarty R. A. , Surjaatmadja J. B. , Chambers R. W. , Grundmann S. R. 
Published: December 2007

Summary
This paper presents the results of a study on an openhole well that was treated with a new fracturing process—hydrajet fracturing. In only a single pass, hydrajet fracturing allows operators to use high-pressure jets to place multiple fractures accurately in several locations in a well. To fracture the well most effectively, the process uses surface and downhole data recorders to monitor well conditions. Study results show that the hydrajet fracturing process is an effective, economical method for fracture-treating openhole horizontal wells.
Wellbore Storage and Skin Effects During the Transient Flow of Non-Newtonian Power-Law Fluids in Porous Media
Authors: Ikoku Chi U. , Ramey Henry J. 
Published: December 2007

AbstractA model recently presented by Ikoku and Ramey for non-Newtonian power-law flow in porous media was extended to flow in finite circular reservoirs. A constant flow rate was stipulated at the wellbore, and two boundary conditions were considered: no-flow outer boundary and constant-pressure outer boundary. The results were used to derive a new expression for the stabilization time for power-law flow in porous media.Wellbore storage and skin effects always distort the transient pressure behavior of wells in petroleum reservoirs. It is important to investigate the consequences of these phenomena and be able to interpret real well test information. This paper considers the effects of skin and wellbore storage on the transient flow of non-Newtonian power-law fluids in petroleum reservoirs.A new numerical wellbore storage simulator was used to study the effects of skin and wellbore storage during the transient flow of power-law fluids in infinitely large and finite circular reservoirs. Results are presented both in tabular form and as log-log graphs of dimensionless pressures vs dimensionless times. The log-log graphs may be used in a type-curve matching procedure to analyze short-time well test data.The early period is dominated by wellbore storage effect. A new expression was obtained for the duration of wellbore storage effect when skin exists for infinitely large reservoirs. This criterion is not valid for finite circular reservoirs with no-flow outer boundary or constant-pressure outer boundary. Results indicate that there is no apparent end of wellbore storage effect for the no-flow outer boundary condition for the values of external radius presented. New relationships were derived for skin presented. New relationships were derived for skin factor and "effective well radius" for power-law flow.
Gel Propagation Through Fractures
Authors: Seright R. S. 
Published: December 2007

Summary
Based on experimental results, a model was developed to quantify gel propagation and dehydration during extrusion through fractures. To maximize gel penetration along fractures, the greatest practical injection rate should be used. On the other hand, in wide fractures or near the end of gel injection, gel dehydration may be desirable to form rigid gels that are less likely to wash out after placement. In these applications, reduced injection rates may be appropriate. Significant advantages could be realized for gels made with a polymer that has the largest available molecular weight.
The Analysis and Prediction of Electric Submersible Pump Failures in the Milne Point Field, Alaska
Authors: Sawaryn S. J. , Grames K. N. , Whelehan O. P. 
Published: December 2007

SummaryElectric submersible pumps (ESPs) are the predominant lift method used in the Milne Point field, Alaska. Each year, approximately 50 ESP failures occur, adversely affecting lifting costs, rig utility, and production. Statistical methods based on the Weibull distribution and the bathtub reliability model have been used to analyze ESP reliability data collected over a 13-year period. This analysis differs from earlier works by treating a portion of the infant failures (the early part of the bathtub model) as a series of Bernoulli trials. Analysis shows that the three main factors affecting ESP reliability in the Milne Point field are reservoir, sand control, and whether the ESP is the first installed in a well or is a replacement. Further, the ESP failure rate is shown to be dynamic, influenced by the delivery of new wells and the time lag between failure and replacement. The results have been incorporated into a computer-based failure simulator that uses Monte Carlo techniques to simulate the failure rates. Numerical values for the statistical parameters are included with the details of the simulator.The simulator is currently used within the Milne Point field asset as a planning tool to establish changes in rig utility, production loss, and ESP replacement strategies in a cash-constrained environment. It is also used to assess improvements in ESP performance and to secure commercial terms for ESP lease and purchase options. In the future, it is recommended that the simulator be used, with suitable analog data, to predict the economic impacts of ESP failures on development programs before sanction.
Wax Precipitation in Gas Condensate Mixtures
Authors: Nichita Dan Vladimir , Goual Lamia , Firoozabadi Abbas 
Published: December 2007

Summary
Wax precipitation for gas condensate fluids was studied in detail with a thermodynamic model. It was found that the precipitated wax phase can exhibit retrograde phenomena similar to that in gas condensates. As a result of pressure decrease (at a constant temperature), the amount of precipitated wax may first increase, then decrease, then increase again.
The effect of pressure on wax precipitation from gas condensates was also studied. Pressure often shows an opposite effect in wax precipitation to that in liquids; however, the pressure effect is not universal.
The model used in this work accounts for both the Poynting correction term and the solid-state phase transitions. Incorporation of these effects reconfirms the suitability of the multisolid phase for wax-precipitation calculations (both the onset and the amount).
Experimental Study of Low-Liquid-Loading Gas-Liquid Flow in Near-Horizontal Pipes
Authors: Meng Weihong , Chen Xuanzheng T. , Kouba Gene E. , Sarica Cem , Brill James P. 
Published: December 2007

Summary
Low-liquid-loading flow in wet-gas pipelines is a common occurrence in the transport of raw gas. The most important parameters governing the flow behavior are pipe geometry (inclination angle and diameter), operating conditions (flow rate, pressure, and temperature), and physical properties of the gas and liquid (density, viscosity, and surface tension). In this study, extensive experiments were conducted with a test loop made of 50.1 mm diameter acrylic pipe with inclination angles from the horizontal of −2°, −1°, 0°, 1°, and 2°. Gas and liquid superficial velocities ranged from 5 to 25 m/s and from 0.001 to 0.053 m/s, respectively. In-situ liquid loading ranged from 150 to 1800 m3. The flow patterns studied were stratified (smooth and wavy) and annular. Measured parameters included gas and liquid volumetric flow rates, liquid-film flow rate, pressure drop, temperature, liquid holdup, and droplet deposition rate.
The experimental results show that there is a broad gas velocity range for the transition from stratified to intermittent flow at low liquid loading. Entrainment can occur in the gas core at relatively low velocities, and droplet deposition occurs simultaneously with entrainment. An increase in gas velocity did not increase the liquid entrainment fraction over a relatively broad range of velocities. However, an increase in the liquid flow rate did increase the liquid entrainment fraction. In the annular flow region, a new phenomenon was observed at certain superficial gas velocities; an increase in the liquid flow rate decreased the liquid-film flow rate and liquid holdup and increased the entrainment flow rate. This phenomenon may have a significant impact on operations to sweep liquids from wet-gas pipelines. Seven correlations of the liquid entrainment onset point and the entrainment fraction in the gas core are evaluated. The interfacial friction-factor closure relationship should be different for upward flow when compared to horizontal and downward stratified flow, owing to the existence of counter-current flow in upward-inclined pipes.
Improved Production Forecasts and History Matching Using Approximate Fluid-Flow Simulators
Authors: Omre Henning , Lødøen Ole Petter 
Published: December 2007

Summary
Forecasts of production with associated uncertainties must be based on a stochastic model of the reservoir variables and a fluid-flow simulator. The latter is usually very computationally demanding to activate. Approximate fluid-flow simulators based on upscaling of the reservoir variables are frequently used to assess the forecasts with uncertainties. The upscaling introduces biases and changes the error structures in the production forecasts, however. A production forecast model that accounts for these biases and changed error structures is defined, and estimators for the model parameters are specified. Forecasts both at the appraisal stage and the production stage including history matching are discussed. The so-called "ranking problem" is formalized and solved as a part of the study. The results are demonstrated and verified on a large case study inspired by the Troll field in the North Sea.