bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modelling of Both Near-Wellbore Damage and Natural Cleanup of Horizontal Wells Drilled With a Water-Based Mud
Authors: Ding Y. , Longeron D. , Renard G. , Audibert A. 
Published: December 2007

Abstract
Prediction of formation damage that occurs in horizontal wells, often open hole completed, is a critical point for optimising an oil field development. The economic impact of near wellbore induced drilling-damage and cleanup efficiency has led to make significant progress in both experimental and numerical studies in order to assess the wellbore flow properties during oil production.
There is a fundamental difference between water-based and oil-based mud invasions. In an oil-bearing formation, the displacement of the oil in place with an oil-based mud (OBM) filtrate is a miscible displacement process, while the displacement with a water-based mud (WBM) filtrate is a two-phase flow process (imbibition), generating high wetting phase saturations in the invaded zone. Then, during oil back flow, a portion of the wetting phase is trapped, leading to residual wetting phase saturations greater than the initial ones. Even in the absence of chemical interactions between filtrate and fluids in place, this induces an adverse water/oil relative permeability effect, which is an additional permeability impairment. In a previous paper, a methodology combining both experimental and numerical approach was presented to evaluate the natural cleanup of horizontal wells drilled with an oil-based mud (OBM). This paper presents an extension of the methodology for simulating both i) near wellbore invasion and permeability damage generated with a water-based mud (WBM), and ii) natural cleanup during oil back flow when the well is put under production.
This paper describes a numerical approach to model the formation damage with WBM and predict well performance for natural clean up when the well is subject to a pressure drawdown. The kinetics of mud filtrate invasion, the filter cake properties and the filtrate/oil relative permeability curves in imbibition and drainage, together with damaged and return permeabilities are obtained from specific mud damage laboratory tests. Using these data, the mud filtrate invasion during the drilling phase is simulated, leading to a cone-type invasion depth along the horizontal well. This approach has allowed us to study the impact of various parameters related to fluids or cake properties, drilling conditions and natural cleanup process on the well performance.
Quantitative Analysis of Mechanisms for Water-Related Sand Production
Authors: Han G. , Dusseault M. B. 
Published: December 2007

Abstract
It is well known that saturation changes of the rock-wetting phase or alterations in wetness can lead to sand instability, therefore sand production. Several possible mechanisms are discussed in the paper, among which chemical reactions between water and sand and the changes of capillary force as a part of cohesive strength are focused upon quantitatively.
Based on the time frame of sand production record, four major possible chemical reactions between reservoir sand and formation water are identified and analyzed, including quartz hydrolysis, carbonate dissolution, ferruginous deposits and clay swelling. Those reactions increase sand instability either through altering the surface energy of the sand and physically changing the shape and size of cement, (known as Rebinder effect), or locally increasing the pressure gradient. The possibility to quantify the effects of those reactions is discussed and the main difficulties are pointed out.
Resorting to an analytical model at the grain scale, which accounts for meniscus behavior and properties in two-phase liquid systems and expresses the results in terms of capillary bond force and a tensile strength in a Mohr-Coulomb plot, the manner and magnitude of the capillary force influence on sand stability after water breakthrough are quantitatively described. It is found that, at grain scale level, the capillary cohesive force is one to three orders higher than the destabilizing seepage force from fluid pressure gradient, depending on particle sizes. Therefore it should not be neglected in the analysis of sand instability. Furthermore surface tension of fluids is found to be linearly related to capillary bond force and therefore to rock strength (tensile strength or UCS), the magnitude of which highly depends on the sand particle size, especially when particles are small. The model is able to successfully explain many reported phenomena about both capillary force and water-related sand production.
As a conclusion, changes of capillary force with water saturation may have more influence on sand failure than chemical reactions in weakly consolidated sandstone at the beginning of water breakthrough. After some critical water saturation, the capillary strength diminishes and chemical reactions may become dominant over time.
Coupled Reservoir-Geomechanics Model with Sand Erosion for Sand Rate and Enhanced Production Prediction
Authors: Wang Yarlong , Xue Shifeng 
Published: December 2007

AbstractA fully coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena both in heavy-oil reservoirs (i.e. Northwestern Canada) and conventional oil reservoirs (i.e. North Sea). The model is implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. A sand erosion model is postulated after the onset of sand production, which is determined based on the degree of plastic deformation inside the reservoir formation calculated by the coupled reservoir-geomechanics model. Both the enhanced production and the ranges of the enhanced or sanding zone are calculated, the effect of solid production on oil recovery and enhancement are analyzed. Field data for solid production and enhanced oil production from Frog Lake (Lloydminster, Canada) are used to validate the model for the sand rate and sand production. Our studies indicate that the enhanced oil production can be contributed by either (1) the a large-scale reservoir formation mobility improvement, (i.e. wormhole type model), by (2) a higher fluid velocity due to the movement of the sand particles according to the modified Darcy's flow, or by (3) an effective well radius increase or negative skin development due to sand erosion if formation does not permit an extensive erosional zone. Such an improvement on productivity reduces the near well pressure gradient so that the sanding potential is weakened, but permits an easier path for oil to flow into the well due to an enhanced permeability. Two-phase flow can affect pressure gradient and formation residual cohesion due to capillary pressure buildup. Indirectly, production enhancement strategy can be controlled by the water saturation distribution and development, as the success and economic value of a field operation can depend on if sand production can be induced or not. Such an analogy can also be used for a completion strategy by allowing a certain amount of sand production before gravel pack in high flow-rate reservoir.
A Numerical Model to Study the Formation Damage by Rock Deformation from Well Test Analysis
Authors: Osorio Jose Gildardo , Wills Alejandro , Alcalde Osmar Rene 
Published: December 2007

Abstract
In oil/gas reservoirs, the state of stress changes as fluid production/injection from/into the reservoir takes place. Also, petrophysical and geomechanical properties may change due to the variation of the effective stress. However, this consideration is seldom taken into account in well test analysis.
This paper presents a numerical, fully coupled, fluid- flow/geomechanical model to perform well test analysis in stress-sensitive reservoirs. The governing equations are developed in cylindrical coordinates honoring the geometry of the flow lines characterizing the drainage area in most well tests. The model is a 3D, point distributed, finite-difference simulator which applies a fully implicit discretization scheme to ensure maximum stability.
The model assumes isothermal, single-phase fluid-flow (slightly compressible fluid). Infinite and finite acting behavior is allowed during the well test. Reservoir properties are allowed to change from one layer to another. Both cases isotropic and anisotropic rock property behaviors are considered in the model. The rock behaves as elastic system whose deformation is described by nonlinear theory (the mechanical properties are function of the mean effective stress).
The results show that in stress-sensitive reservoirs the permeability decreases with production time reaching its minimum value near the wellbore and moving more and more into the reservoir as production time increases. After a certain production time, the permeability distribution reaches a constant value. An important finding from this study is that the damage caused by rock deformation is irreversible; therefore, its early detection and treatment is essential for optimum reservoir management.
Optimization of Matrix Acidization by Elementary Capture Spectroscopy Log
Authors: Mohamad Natsir , Defrian Basya S. , Kusaka Koji , Simatupang Johnson 
Published: December 2007

Abstract
Beringin field D-structure (Beringin-D) is located in South Sumatra, Indonesia, operated by Perusahaan Pertamnabgan Minyak dan Gas Bumi Negara (Pertamina), DOH Prabumulih. Since its discovery in 1987, some 30 wells have been drilled and current total oil production is approximately 1,700 BOPD. The geological structure of this field is homocline with several faults across the field and several late Oligocene/early Miocene hydrocarbon-bearing sandstone layers are deposited on basement or on shale by on-lapping.
In the past, formation damage problems were encountered in Beringin-D and matrix acidization was applied to improve well productivity. However, the results were mixed and the main reason for failed acidization was thought to be lack of knowledge of clay types in the formation; thus, composition of the treatment fluid was not optimized. Therefore, to identify clay types present in the formation, an ECS* Elementary Capture Spectroscopy log was run on Well BRG-19. The ECS tool is a wireline-run neutron device that can detect important elements in openhole or in cased hole. Combined with NGS* Natural Gamma Ray Spectrometry log and other information, a comprehensive formation mineralogy analysis is possible.
Prior to obtaining the ECS/NGS logs, higher than 10% montmorillonite (smectite) concentration was assumed and sandstone acid (SSA) had been commonly used for Beringin-D wells. However, the log on BRG-19 revealed that the interval of interest contained 8% kaolinite and 3% montmorillonite. On the basis of this new finding, standard acid was used instead of the SSA, and the result showed 100% oil production improvement compared to the average 30% improvement in the past. Also, the SSA costs approximately twice as much as the standard acid.
The ECS and NGS logs helped us identify and quantify clays in situ, and we used this information to optimize matrix acidization through a field case.
Perforating System Selection for Optimum Well Inflow Performance
Authors: Folse Kent , Allin Melissa , Chow Chris , Hardesty John 
Published: December 2007

Abstract
Oilfield operators and service companies continually face challenges to provide completions that not only produce at optimum levels but also accelerate return on investment (ROI). These operational demands are further complicated by the fact that the range of reservoir scenarios continues to expand. In attempting to satisfy these needs, one component of the completion process is often over looked or taken for granted — the perforation process.
In the energy industry, many companies base their selection of shaped-charge perforators solely on API Section I criteria such as depth of penetration or casing-exit hole size. Other factors, such as the actual performance of given shaped charges at in situ conditions, also should be evaluated when making perforating decisions for the completion process. Focusing perforator system performance on reservoir productivity rather than on the shaped-charge performance optimized for concrete testing (which is the case with API Section I) can ultimately lead to significant improvement in well inflow performance.
Although API RP43 Section IV perforating procedures (to evaluate well perforators under in-situ conditions) have existed since 1985, there has been limited field validation of experimental results and model predictions based on these procedures.1-3 This paper discusses insights gained from a series of Section IV tests conducted with Berea and Castlegate sandstone cores under varying in situ conditions. The Section IV lab experiments represent physical models of the near-wellbore region during perforation and completion processes under in-situ stress. The results of these experiments indicate that understanding the inherent system inadequacies and experimental conditions is critical to proper integration of the results with theoretical models and field data.
Application of a Novel, High-Density, Brine-Based, Biopolymer-Free Reservoir Drilling Fluid: A Case Study
Authors: Knox David , Bye Gry Kristvik , Horton Robert , Svoboda Charlie , Foxenberg William , Tresco Kim 
Published: December 2007

Abstract
Low-solids, brine-based reservoir drilling fluids are widely accepted as being beneficial with respect te a rheological profile suitable for high performance reservoir drillto minimising fluid-related formation damage and optimising compatibility with the completion design. Traditionally, the maximum density attainable with a low solids fluid has been limited – either due to the prohibitively high cost of the base brine required, or the poor performance of viscosifying biopolymers in a divalent cation environment.
A reservoir drilling fluid has been developed that exhibits unusually high quality rheological behaviour in high-density calcium- and zinc-based brines, without the aid of a biopolymer.
The first field trial of this fluid was on the reservoir section of well 34/10 I-1-AH, in the Gulfaks Satellites Development in the Norwegian Sector of the North Sea. Fluid properties during the pre-testing, mixing, drilling and completion of this section are detailed in this paper.
Formate Brines: A Comprehensive Evaluation of Their Formation Damage Control Properties Under Realistic Reservoir Conditions
Authors: Byrne Michael , Patey Ian , George Liz , Downs John , Turner Jim 
Published: December 2007

Abstract
Monovalent formate brines were first introduced into the oilfield environment in the early-1990's, in response to the industry demand for better drilling and completion fluids to meet the increasingly complex technical challenges posed by modern well construction practices.
After years of rigorous field-testing, in a variety of demanding well construction operations, the formate brines are now acknowledged to be probably the best foundation for any modern high performance drilling and completion fluid. The formate brines are currently having their greatest impact as the primary components of HT/HP reservoir drilling and completion fluid formulations.
A number of field and laboratory tests have indicated that when formate-based formulations are used as reservoir drilling-in and completion fluids they appear to cause less formation damage than some other conventional fluid formulations, and consequently they are often seen to have a beneficial effect on well productivity. Up until now, however, little of this important information has found its way into the public domain.
It has been common practice for a number of the major multinational oil companies to contract a specialist formation damage prediction company to carry out laboratory-scale formation damage tests with formate brines before using these fluids in their well constructions operations. This paper draws together the results of a significant number of these tests carried out by the specialist laboratory using formate-based fluids passed through real reservoir core materials for realistic time periods and under realistic reservoir conditions.
As well as providing a unique insight into the interaction between formate brines and a range of reservoir core materials and reservoir fluid types under simulated downhole conditions, this paper also outlines the methodology developed to ensure that the formation damage tests carried out with formate brines are not influenced by laboratory artefacts.
The conclusion of the paper is that a significant number of laboratory results, obtained under test conditions closely simulating reservoir conditions, tend to lend support to the growing perception that formate brines have valuable formation damage control properties that can be exploited to improve we ll productivity prospects in even the most demanding environments.
Filtration Properties of Oil-in-Water Emulsions containing Solids
Authors: Kassim Al-Riyamy , Sharma Mukul M. 
Published: December 2007

Abstract
This paper is an attempt to study the mechanisms controlling the filtration and fluid leakoff properties of emulsions containing solid particles.
HPHT filtration tests clearly demonstrate that emulsions have the ability to reduce filtrate loss to the formation. However, the emulsion droplets tend to invade the formation and form an internal filter-cake. This is evident, from the lift-off pressures needed to initiate flow-back and deep invasion of emulsion droplets in long core experiments. Emulsions containing solids (CaCO3 in our case) had lower filtrate volume and higher return permeabilities than solids free fluids. The effects of percent oil, injection pressure, core permeability, temperature and viscosity of the continuous phase were investigated. Injection pressure and core permeability had major influences on the filtration properties of the emulsified completion fluids. Higher injection pressures increased internal damage and lowered the return permeability. Higher permeability cores had higher filtrate loss. Emulsion droplets were observed in the effluent and solid particles are needed to form a stable external filter-cake.
Long core experiments showed that using emulsions containing acid-soluble solid particles have 100% return permeability after an acid squeeze showing that the emulsion droplet invasion depth is less than one inch. It is shown that solids free fluids had the highest formation damage and higher lift-off pressures.
Analysis of the fluid leakoff data indicates that emulsions containing solids do not behave as classical filtration theory predicts. Due to the invasion of emulsion droplets into the formation the data did not fit the calculated filtration profiles.
Sizing the solid particles and the emulsion droplets in muds according to the permeability of the rock and the external cake is important in forming stable external filter-cakes. This increases the return permeability and results in easier cake removal (low lift-off pressures).
Use of a pH Sensitive Polymer for Conformance Control
Authors: Al-Anazi Hamoud A. , Sharma Mukul M. 
Published: December 2007

Abstract
A new strategy of using pH sensitive polymers for conformance control is proposed. The rheological properties of some polymers such as anionic derivatives of polyacrylic acid are shown to be very pH sensitive. For example, their viscosity varies from 5 cp at a pH of 2.5 to 20,000 cp at a pH above 6.0. This rheological behavior is reversible as the pH is cycled. Rheological data is presented at different polymer concentrations, temperatures and in solutions with different ionic strength. The effect of temperature on the rheological properties of the polymer is shown to be small. Compatibility tests showed that this polymer is compatible with most brines (NaCl, NH4Cl, and KCl).
Core flow experiments were conducted on Berea cores. The results showed that the polymer solution was easily propagated through 6 inch long cores due to its low initial viscosity (~5cp). The polymer solution formed a rigid gel inside the pores after a shut-in period of 24 hours as the pH of the fluid increased above 6. The gelled polymer was found to be stable up to the maximum examined pressure gradients of 4000 psi /ft across the core. Experiments were conducted by using acid pre-flushes ahead of the polymer solution. These results indicate that the polymer can be placed deep into a formation by using pre-flushes designed for a specific rock mineralogy.
The pH sensitive polymers studied here are excellent candidates for conformance control. It may also be possible to use them for temporary zonal isolation since they can be easily broken down with a mild acid wash and flowback.
Blake Seawater Injection Well Perforation Optimization
Authors: Paveley Craig , Brown James , Edward Du , Beesley Martin , Patey Ian , Byrne Michael 
Published: December 2007

Abstract
The Blake field, in the Outer Moray Firth, UKCS, is a shallow thin oil reservoir in the Captain sandstone formation. The initial subsea development consists of 6 production and 2 seawater injection wells tied back to the Bleoholm FPSO, 12 km away. The production wells are horizontal openhole completions with standalone sand screens whilst the injection wells are high-angle cased and perforated.
The principal keys to the successful development of Blake were the placement of the production wells relative to the oil-water and gas-oil contacts and the efficiency of the water injection scheme.
On completion and testing of the first seawater injection well, injectivity was found to be significantly less than expected and therefore had a potential material impact on the water injection strategy for the field. As a result focus was placed on understanding the key mechanisms influenceing well performance and to perform all necessary work to mitigate the effects in the second water injector. This work consisted of coreflood tests, diagnostic perforation surge flow modeling, perforation performance remodeling and well design and operational changes.
From the coreflood tests it became apparent that formation fines mobilisation and migration was a major contributor to under performance. The surge flow modelling indicated that the underbalance applied when perforating the first injection well would have induced high surge flow rates potentially causing formation damage through rapid fines mobilisation; the underbalance having been designed to optimise perforation performance.
As a result of this work the second seawater injection well was perforated with a lower underbalance set to limit the surge flow rate; this underbalance being significantly lower than the theoretical optimum required for perforation effectiveness. The initial injectivity testing on the second well has proved to be significantly better than for the first well.
The paper outlines the diagnostic coreflood testing completed and how the results were applied together with the perforation surge flow modelling and perforation operational design to establish an operational strategy to optimise seawater injectivity on Blake; including well design changes.