bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Coupled Reservoir-Geomechanics Model and Applications to Wellbore Stability and Sand Prediction
Authors: Wang Yarlong , Lu Baoping 
Published: December 2007

Abstract
Sand production and open hole collapse during production have been a great concern for production engineer, as the detrimental consequences are often associated to a desirable high production. Sand production usually occurs under a high-pressure gradient in poorly cemented formations. Whereas wellbore collapses could occur if a bottom hole pressure is below a certain level or production reaches a certain rate, i.e. during underbalanced drilling, under a high rate production, or when an aggressive well completion for high production is used. To determine the critical flow rate or bottom hole pressure, a coupled reservoir-geomechanics model is developed to simulate the interaction between reservoir flow and deformation. The model is developed and implemented numerically in Finite Element method by fully coupling a comprehensive geomechanics model to a three-phase reservoir behavior model. Gas component behavior is only considered below a bubble point, and it remains inside the oil phase before a critical gas saturation can be reached in our simulations. The effects of multiphase behavior on near well stresses and deformations, including high compressible gas component in the solution gas phase (foamy oil) are analyzed. Both Mohr-Coulomb and Drucker-Prager criteria are introduced to outline the plastic yielding surface and to govern the plastic flow. The effects of the stress-dependent formation moduli and permeability changes are permissible. The final stability and the onset of sand production are determined by a critical effective plastic strain and zero effective radial stress, whichever condition occurs first. Our studies indicate that, other than the well known factors such as bottomhole pressure and drawdonw, well stability and sanding risks are critically controlled by (1) the solution-gas behavior, (2) the formation stiffness, and (3) the residual cohesion. The latter can be senstitive to the wetting phase saturation. Considering production enhancement and formation damage, the reservoir porosity increase due to formation dilation is simulated, which can generate a negative skin near a well and result in a production enhancement. Our model can be used to calculate both the enhanced production and the ranges of the enhanced zone.
Sand Handling During Multiphase Operations With Twin-Screw Pumps
Authors: Dorenbos Cornelis (Kees) , Müeller-Link Dietrich , Jäeschke Axel 
Published: December 2007

Abstract
It is sure that production equipment has to handle solids, which are released from the reservoir rock during hydrocarbon extraction. Subsequently it is necessary to define all operational consequences and circumstances at an early project stage. But solids released during well intervention operations or disposal of any kind of fluid through the flowlines strictly have to be avoided or taken care of by special actions. This is especially true when rotating equipment such as twin-screw multiphase pumps are part of the downstream production train.
Operation parameters mostly influencing the wear, such as axial fluid velocities and product viscosity are outlined. The wear pattern due to erosion as well as abrasion occurring in Multiphase Pumps with its effect on boosting operations is described. Increasing suction pressure and pump temperature definitely are a sign for a decreasing capacity of the pump so that production forecast can not be met any longer. Excessive leakage from the mechanical seals are another one.
Preventive measures are to be taken in case of solids transport anticipated. Material selection, but moreover surface treatment of the effected pump internals offer a variety of chances to reduce the wear.
But neither can such wear be excluded nor avoided as it is the same for any other equipment used in such environment.
Special attention is given to the mechanical seals, whose wear sometimes can stop operations immediately. Different material selections for this equipment seldom offers improvement, and may even lead to a worse situation.
Equipment used to filter the fluid stream can be used. It is necessary to design them for multiphase flow with sometimes severe slugging to occur. Strainers (at least temporary) are a must after any work on the flowlines to the pump.
Examples from field installations will finalise this paper outlining the experience gained under a variety of operating parameters, surface treatments, mechanical seal arrangements, and filtering equipment
Contribution of Horizontal-Well Log and Pressure Data in Stochastic Modeling
Authors: Aissaoui Karim , Tiab Djebbar 
Published: December 2007

Abstract
In heterogeneous reservoirs like Hassi Messaoud, the exact interwell location of each reservoir sandstone body can not be in most cases easily located, and the potential of drilling unsuccessful production wells is usually present. In this situation a reservoir characterization model with usable uncertainties is needed.
Conventional modeling techniques fail to quantify heterogeneities in lateral direction, however horiontal well data appear to compensate for this lack of information, providing some knowledge about variability of reservoir parameters, using data recorded along the horizontal drainhole of horizontal wells, hence providing adequate measurements of reservoir properties in the interwell locations.
In this study a petrophysical model was generated for the north east area of Hassi Messaoud field comprising four horizontal wells. The generated models of porosity permeability and shale distribution were in agreement with Hassi Messaoud braided fluvial depositional model. The facies lateral variations have confirmed the nonuniform depletion throughout this sector of the field, which has led to its zonation.
Once the reservoir characterization was complete, the generated model was validated using a full-field model of North East area`, that involves history match of each well individually.
New View on Continuous-Removal Liquids from Gas Wells
Authors: Li Min , Lei Sun , Li Shilun 
Published: December 2007

Abstract
To prevent gas wells from load-up, it is necessary to study the cause of load-up and condition for liquids to accumulate in wellbore. The paper adopts the view that the liquids droplets entrained in gas wells tend to be flat shape and deduce new formulae for continuous removal liquid from gas wells. The results calculated from the formulae are smaller than that of conventional Turner's. However, the predicted results accord with practical situation of gas wells in China gas fields. In addition, for the easier application purpose, the paper put forward simple formulae from the deduced formulae under analyzing different factors affecting removal liquids from gas wells. The model explains why many gas wells produce without load-up when the producing rate is by far smaller than that of Turner's minimum producing rate. In order to help engineer working in gas fields judge load-up effluence on gas well production, the paper analyzes the production performance of load-up and near load-up as well as unloading gas wells through wellhead producing performance figures.
Design and Performance of Miscible Flood Displacement
Authors: Laieb Krimo , Tiab Djebbar 
Published: December 2007

Abstract
Oil recovery by miscible gas injection process has been a topic of research, development, and field testing for more than 40 years. There is still some disagreement in the interpretation of laboratory, field-test data and selection of predictive methods. Field experiments, however, have disclosed a number of problems with hydrocarbon miscible flooding that limit the oil recovery and diminish the economic attractiveness of these processes. Due to the fact that there is no generalized engineering method or model that adequately accounts for all the factors, each model tends to emphasize one or more aspects of the displacement while neglecting other aspects for the sake of tractability.
A parametric study is done, using a 3-D, compositional numerical simulator "VIP" in order to design the model and analyze the results and performance of miscible gas injection in Hassi Berkine South field. A 9-component PR EOS was used to describe the phase behavior using IMPES formulation. The process of simulation study to design and optimize the full field model included the following steps: Start with a basic run, used as a reference case.Compare the base case (miscible gas injection) with water injection process.Consider the phase behavior effect.The reservoir description effect.Vertical sweep out.Partial recovery of miscible flood.Influence of grid variation.
A cross sectional model was used to represent the simulation domain that covered about 5000 ft² in area and 100 ft in thickness. All the runs consisted of two wells, penetrating the entire layers, the injector in the first cell and the producer in the last one.
From the results it has been concluded that the use of horizontal well data has compensated for lack of information about reservoir heterogeneity in lateral direction of the interwell locations.
South Wasson Clear Fork Reservoir Model: Outcrop to Subsurface via Rock-Fabric Method
Authors: Lucia F. J. , Jennings J. W. , Ruppel S. C. 
Published: December 2007

Abstract
South Wasson Clear Fork field produces from two reservoirs, the middle Clear Fork, with a seal located within the upper Clear Fork Formation, and the lower Clear Fork, with a seal located in the Tubb Formation. Six sequences have been defined on the basis of facies succession, seismic interpretation, and outcrop analog studies in Apache Canyon, Sierra Diablo Mountains, West Texas. Rock-fabric/petrophysical studies have shown that a single porosity-permeability transform and porosity-saturation-capillary-pressure model can be used to calculate permeability and water saturation in uncored wells. Five rock fabrics have been described, and all plot in the petrophysical class 1 field. This surprising result is related to the presence of large volumes of poikilotopic anhydrite, which reduces porosity but has little effect on pore size or perme-ability. Permeability values calculated from porosity logs are distributed in the interwell environment within a high-frequency-cycle (HFC) stratigraphic framework. Analog outcrop studies demonstrate that the Clear Fork Formation can be characterized by upward shallowing (HFC’s). Identifying HFC’s, however, is made difficult because of the high uranium content of the Clear Fork and the lack of a relationship between water saturation and rock fabric. A statistical relationship between porosity and rock fabric is developed, however, that allows porosity to be used as a surrogate for rock fabric, and vertical increases in porosity are interpreted as mud-dominated to grain-dominated fabric successions and used to define HFC’s. The HFC’s are divided into two rock-fabric flow layers, an upper, grain-dominated and a lower, mud-dominated layer, in order to preserve high-and low-permeability intervals. Permeability data from the outcrop analog in Apache Canyon are used to demonstrate that the vertical variability seen in the log calculations within the rock-fabric flow units does not represent permeable strata but is statistical variability at a near-random scale.
Reservoir Zonation in the Barnhart Field: Ellenburger Group, Ozona Uplift, Reagan County, Texas
Authors: Hunt Tim J. 
Published: December 2007

Abstract
Barnhart Field was discovered in 1941 on the Ozona Uplift, southeastern Reagan County, Texas. The field produces from the Ellenburger Group on approximately 10,000 acres that can be divided into a southern part on University Lands and a northern part on private land. Two pilot waterfloods were attempted; neither was successful. The field was essentially abandoned in 1976 after producing more that 16 million BO. The structure of the field is an asymmetrical anticline trending northeast – southwest with the crest on the northern part of the field. Structure alone does not appear to control production because the southern part produced slightly more oil than the northern part. Insoluble residue analyses and lateral-log correlations indicate the Ellenburger in the northern part of the field was more deeply eroded than in the southern part. The Ellenburger Group, in this field, can be divided into three pay zones, the Upper Honeycut, the Lower Honeycut and the Gorman. The Upper Honeycut produces only in the southern part of the field and may have the best developed porosity in coarse crystalline dolomite. An isopach of the Honeycut pay zones shows fair agreement between thickness and production. The Gorman pay zone does not correlate well indicating that production cannot be explained by gross isopachs alone.
Field-Scale Characterization of Permeability and Saturation Distribution Using Partitioning Tracer Tests: The Ranger Field, Texas
Authors: Iliassov Pavel A. , Datta-Gupta Akhil , Vasco D. W. 
Published: December 2007

Abstract
This paper discusses the application of an efficient streamline-based inversion method to a large multi-well multi-tracer Partitioning Interwell Tracer Test (PITT) in the McClesky sandstone, Ranger Field, Texas, to characterize both permeability and oil saturation distribution. During a typical PITT, a conservative and a partitioning tracer are injected into the reservoir. The partitioning tracer gets partially absorbed into the oil phase, leading to a separation in the tracer responses that can be used to infer oil saturation distribution in the tracer-swept area. Our approach is extremely efficient because it relies on analytic computation of the sensitivity of the tracer response to reservoir parameters such as permeability and saturation using a single streamline simulation. We follow a two step procedure whereby we first match the conservative tracer response to determine the permeability distribution and then match the partitioning tracer response to obtain oil saturation distribution in the reservoir. The entire history matching took less than 6 hours in a PC as opposed to several months typically required for a manual history matching.
We compared our results to a manual history match obtained using a finite-difference simulator. Both the manual history matching and the streamline-based inversion identified similar large-scale trends in permeability and saturation distribution. However, well-specific matches were significantly improved over those obtained through the manual history matching. Our approach is much more efficient in terms of computation time and effort and the results are less sensitive to personal bias compared to manual history matching. Finally, we discuss a procedure to assess the results in terms of resolution of the estimates of permeability and saturation distribution.
Constraining the Spatial Distribution of Fracture Networks in Naturally Fractured Reservoirs Using Fracture Mechanics and Core Measurements
Authors: Olson Jon E. , Yuan Qiu , Holder Jon , Rijken Peggy 
Published: December 2007

Abstract
Observations of natural fractures in core or image logs typically give limited information on orientation, aperture and intensity. Because of the sparseness of wellbore intersections of fractures, data analysis results in incomplete statistical characterization of the fracture population, leaving interwell characterization almost impossible. Using basic fracture mechanics models and a novel core-testing technique, we propose that the fundamental shape of fracture parameter distributions can be predicted, and that there is a characteristic, quantifiable relationship between fracture length, spacing and aperture. We have performed subcritical fracture growth tests on numerous core samples, using credit card sized specimens, demonstrating the ability to characterize fracture mechanics properties of rock on a bed by bed basis. Using the subcritical index, a parameter that quantifies the relationship between natural fracture propagation velocity and tip loading conditions, we can predict the degree of fracture spacing regularity or clustering for a given reservoir bed. This subcritical parameter, along with information on the number of initial natural flaws in a given rock type, allows us to quantify the expected length distribution of the fractures. Under many conditions, as verified from outcrop data, fracture length is theoretically expected to follow an exponential distribution. Since natural fracture length is typically unobservable in subsurface data, we derive relationships that relate fracture length to aperture and spacing, both more readily measurable quantities. With this information, matrix block size and fracture drainage continuity can be estimated for the purpose of flow simulation in a fractured reservoir.
Drilling with Aerated Drilling Fluid from a Floating Unit Part 2: Drilling the Well
Authors: Lage Antonio C. V. M. , Santos Helio , Silva Paulo R. C. 
Published: December 2007

Abstract
The biggest challenge of the aerated fluid drilling technology development was overcome with the well in Albacora being drilled with the semi-submersible platform Petrobras 17 (P17). A previous paper1 described the stages before the drilling activity: planning, new equipment, rig modifications and all the preparation for drilling the well.
This paper describes the drilling operation itself. All the important points and differences relative to the conventional drilling method are highlighted, with special emphasis to the new equipment installed at the platform: the vertical compact separator, the automatic control system, and the RiserCap™rotating control head. The operation of the new equipment, performance and the problems observed are presented and discussed. The points of improvement are suggested and ways to move forward with this new technology also discussed in the paper.
The present work also addresses the positive impact of this field test relative to the implementation of the light-weight fluids technology from floating units. This initiative has been carried out systematically by Petrobras in the form of a Joint Industry Project (JIP) and has been congregating operators, service companies and consultants. The next steps of this project to use effectively light-weight fluids for drilling in deepwater are discussed. The experienced obtained with this operation was crucial to direct and guide the most important points to be studied and developed in the next phase of the project.
Chemical and Thermal Effects on Wellbore Stability of Shale Formations
Authors: Yu M. , Chen G. , Chenevert M. E. , Sharma M. M. 
Published: December 2007

Abstract
A new three-dimensional wellbore stability model is presented that takes into account thermal stresses and the flux of both water and solutes from drilling fluids (muds) into and out of shale formations. Mechanical stresses around a wellbore placed at any arbitrary orientation in a 3-dimensional stress field are coupled with changes in temperature and pore pressure due to water and solute fluxes. The radial and azimuthal variation in the stress distribution and the "failure index" are computed to check for wellbore failure. This model accounts for the hindered diffusion of solutes as well as the osmotically driven flow of water into the shale. The model for the first time allows a user to study the role of solute properties on wellbore stability.
Results from the model show that a maxima or minima in pore pressure can be obtained within a shale. This leads to wellbore failure not always at the wellbore wall as is most commonly assumed but to failure at some distance inside the shale. Since the fluxes of water and solute, and temperature, are time dependent, a clearly time dependent wellbore failure is observed. The time to wellbore failure is shown to be related to the rate of solute and water invasion. Comparisons with experiments conducted with a variety of solutes on different shales show excellent agreement with model results.
It is shown in this study that the solutes present in the mud play an important role in determining not only the water activity but also in controlling the alteration of pore pressures in shales. To account for this phenomenon a model is presented to compute the flux of both water and solutes into or out of shales. The relative magnitudes of these fluxes control the changes in pore pressure in the shale when it is exposed to the mud. The effect of the molecular size of the solute, the permeability of the shale and its membrane efficiency are some of the key parameters that are shown to determine the magnitude of the osmotic contribution to pore pressure. A range of behavior is observed if the solute is changed while the water activity is maintained constant. This clearly indicates the importance of the solute flux in controlling the pore pressure in shales.
Critical mud weights are obtained by inspecting the stability of the wellbore wall and the entire near wellbore region. Pore pressures at different time and position are investigated and presented to explain the model results. It is shown in this study that the critical mud weights are strongly time dependent. The effects of permeability, membrane efficiency of shale, solute diffusion coefficient, mud activity and temperature changes are presented in this work. The collapse and fracture effects of cooling and heating the formations are also presented.
A powerful tool has been developed which can be used to perform thorough investigations of the wellbore stability problem. A user-friendly interface has been developed to ease usage.
Underbalanced and Low-head Drilling Operations: Real Time Interpretation of Measured Data and Operational Support
Authors: Lorentzen Rolf J. , Fjelde Kjell Kåre , Frøyen Jonny , Lage Antonio C. V. M. , Nævdal Geir , Vefring Erlend H. 
Published: December 2007

Abstract
The accurate prediction of the downhole pressures and the returning flow rates in low-head drilling (LHD) and underbalanced drilling operations (UBD) is a major concern in the oil industry. The present work shows an original formulation of a dynamic two-phase flow model based on the classic drift-flux set of conservation equations. However, differently from the traditional approach, the closure of the system is obtained by using measured data acquired during the execution of the operation. The innovative concept consists of utilizing mechanistic models that are dependent on unknown parameters. These parameters and the model state are calculated and updated on a regular basis to minimize the differences between model predictions and measured data.
The potential of this new approach is discussed by presenting some transient examples of application. The current study represents a continuation of previous work on real time data interpretation1, and a step in the development of a methodology for the introduction of learning while drilling process in the hydraulic design and follow-up of LHD and UBD operations.