bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combining Matrix Stimulation and Gravel Packing Using a Non-acid Based Fluid
Authors: Armirola F. , Machacon M. , Pinto C. , Milne A. , Lastre M. , Miquilena E. 
Published: June 2011

Abstract
The CaraCara field in the Los Llanos area of Colombia is a highly permeable (1 − 3 Darcy) sandstone with more than 10% total clay content, producing heavy crude. Gravel packing is required to avoid sand production. However, the Productivity Index after conventional gravel packing is only 50% of the open-hole potential due to drill-solids—calcium carbonate —plugging the matrix and fines migration. Non-acid and acid based preflushes have been used to dissolve the drill-solids and fines in the critical near wellbore matrix respectively. However, corrosion, uncontrolled filter cake dissolution, sludging with heavy crude and disposal of spent acid limits the use of acid pre-flushes.
A recently developed non-acid based fluid capable of stimulating high temperature sandstone formations was taken as the starting point to develop a customized solution to remove formation damage and control fines migration for this particular application. The base fluid is chelant such as diammonium EDTA (DAE) to which a low concentration of HF acid is added, most commonly in the form of ammonium bifluoride. The HF acid greatly increases the dissolution of aluminosilicates, while the chelant prevents the precipitation of silica gel. The addition of boric acid effectively retard the dissolution rate of the fluid as boric acid the reacts with the HF acid to form fluoroboric acid (HBF4) which slowly hydrolyses to release HF acid. Fluroboric acid also provides an effective means of fines migration control. By adjusting the concentration of acid salts in the fluid as a function of temperature the fluid can provide effective controlled filter cake removal, matrix stimulation and fines migration control, at temperatures between 120 and 300°F.
The newly developed non-acid fluid system provides some unique advantages for gravel packing and matrix stimulation applications in highly permeable heavy oil reservoirs 1) A single carrier fluid, eliminating the need for preflushes 2) Controlled filter cake dissolution ensuring circulation is maintained while gravel packing horizontal wells. 3) Effective fines migration control. 4) Scale inhibition. 5) Crude compatibility and negligible corrosion rates.
In one field the average productivity index of vertical wells completed using this fluid increased from 0.2 bbl/psi to 0.9 bbl/psi. The final skin values were close to zero and the production remained stable for an extended period of time. A similar fluid when used in horizontal well applications reduced the cleanup time from days to hours. The ability to stimulate while gravel packing optimizes the productivity of dirty sandstones while minimizing the cost.
Engineering Drill-in Fluids to Improve Reservoir Producibility
Authors: van Zanten Ryan , Horton David , Tanche-Larsen Per-Bjarte 
Published: June 2011

Abstract
Preventing formation damage is the primary objective of a drill-in fluid. Damage can occur through many different mechanisms including emulsion blocks, water blocks, polymer/filtrate/particle invasion, precipitates, and improper wetting of the formation. Damage can be remediated by stimulating the formation through fracturing, acidizing or improving flow-back with chemical treatments; however, these post-drilling treatments can significantly increase well construction costs.
Ideally a reservoir drill-in fluid will be tailored to prevent formation damage and protect the producibility of the well. Current methods such as viscosifying filtrate can be engineered to minimize filtrate invasion along with utilizing acid-degradable fluid loss control polymers/bridging particles. Verifying compatibility between the drill-in fluid and formation fluids can help prevent blockages from precipitates or scale. Although it can be minimized, filtrate invasion in water-based drill-in fluids is typically higher than in oil-based drill-in fluids, and such invasion can adversely impact producibility.
This paper investigates the effect of chemical treatments added to the fluid that alter formation wettability and/or eliminate emulsion blocks in oil wells or water blocks in gas wells whilst being penetrated during the drilling process. By applying these treatments, water- and brine-based fluids can achieve return permeabilities similar to oil-based drill-in fluids. The invading aqueous filtrate can be used as a production enhancement tool, allowing us to achieve improved formation producibility. This paper describes the development of a unique technique to chemically alter the drill-in fluid such that the invading filtrate alters the producing rock to optimize production. This can reduce or eliminate the need for remedial treatments and can decrease damage from certain fluid additives such as lubricants and corrosion inhibitors.
Understanding Drill in Fluid Invasion into Multi Layer Reservoirs Satured by Compressible Fluids
Authors: Waldmann A. T. , Martins A. L. , Dannenhauer C. 
Published: June 2011

Abstract
Minimizing fluid invasion is a major issue while drilling reservoir rocks. Large invasion may create several problems in sampling reservoir fluids in exploratory wells. Besides, drilling fluid invasion may also provoke irreversible reservoir damage reducing its long term productivity. A common practice in the industry is the addition of bridging agents in the drilling fluid composition, such as calcium carbonates. Such products would form a low permeability layer at the well walls which would control invasion.
This paper presents a radial model, based on Darcy's law to predict the drilling fluid invasion profile into a multi-layer reservoir rock saturated with a compressible fluid. Results highlight that the differential pressure, the fluid compressibility, the filter cake permeability and the rock properties are important parameters that affect significantly the invasion profile. The proposed methodology is a tool to optimize drilling fluid design to be used in the drilling of reservoir sections in both exploratory and development wells in offshore Brazil fields. The process analysis is illustrated with a series of case studies in offshore exploratory wells drilled in Brazil. The analysis highlights the importance of filtration control and of a dedicated drilling fluid designed for each specific reservoir.
Return to Basics and Proper Planning Opens the Possibility to Acid Stimulate a Difficult Chalk Formation
Authors: Van Domelen Mary , Talib Noor , Glasbergen Gerard 
Published: June 2011

Abstract
In the Danish Central Graben, the Lower Cretaceous reservoir contains significant in-place oil volumes. This formation historically has posed a real challenge to develop because of the extremely low permeability. The low permeability is compounded by the fact that the formation is soft, highly heterogeneous, and can have significant clay content in some areas. Although the Lower Cretaceous chalks represent a wide spread play in the central North Sea, there are no producing analogs.
Thicker Lower Cretaceous reservoir sections in the Valdemar field have been successfully proppant fracture stimulated. Acid stimulation is preferred for the thinner sections; however, early attempts at matrix acid stimulation were very disappointing. Recently, the need to re-enter a well for maintenance allowed three zones to be selectively restimulated using improved execution techniques and a more appropriate acid formulation. Production increase following restimulation of this first well was very encouraging and the lessons learned were applied to a second well; this time a newly drilled well completed in the Tyra Lower Cretaceous reservoir.
This paper summarizes the lessons learned, starting with a review of the previous acid stimulations. Wormhole testing with Lower Cretaceous core material provided important insight toward the selection of the most appropriate acid formulation. Computer modeling was used to determine the most effective perforation patterns, based upon variable formation characteristics along the long, horizontal wellbore. Treatment execution and monitoring included diagnostic injection tests and real-time calculations of acid coverage during the limited-entry perforated completions.
The results of these two wells has been very encouraging and has opened up the possibility for continued testing of acid stimulation techniques in both the Valdemar and Tyra Lower Cretaceous reservoirs.
Mechanically Induced Fracture Face Skin – Insights from Laboratory Testing and Numerical Modeling
Authors: Reinicke Andreas , Blöcher Guido , Zimmermann Günter , Huenges Ernst , Dresen Georg , Stanchits Sergei , Legarth Björn , Makurat Axel 
Published: June 2011

Abstract
In context of this work, a new formation damage mechanism is proposed: the mechanically induced fracture face skin (FFS). This new mechanism results from mechanical interactions between the proppants and the reservoir rock, due to the increasing stress on the rock-proppant system during production. Proppant embedment into the fracture face and proppant crushing leads to fines production and may impair the fracture performance. In order to achieve sustainable, long-term productivity from a reservoir, it is indispensable to understand the hydraulic and mechanical interactions in rock-proppant systems. Permeability measurements on sandstones with propped fractures under stress using different flow cells were performed, allowing localizing and quantifying the mechanical damage at the fracture face. The laboratory experiments identified a permeability reduction at the fracture face up to 90 %. The mechanical damage at the rock-proppant interface begins immediately with loading the rock-proppant system and for fracture closure stresses below 35 MPa; the damage is localized at the fracture face. Microstructure analysis identified quartz grain crushing, fines production and pore space blocking at the fracture face causing the observed mechanically induced FFS. At higher stresses, damage and embedment of the ceramic proppants further reduces the fracture permeability. Numerical modeling of the rock-proppant system identified highly inhomogeneous stress distributions in the granular system of grains and proppants. High tensile stress concentrations beneath the area of contact between quartz grains and proppants are observed even at small differential stress applied to the rock-proppant system. These high stress concentrations are responsible for the early onset of damage at the fracture face. Therefore, even low differential stresses, which are expected under in-situ conditions, may affect the productivity of a hydraulically fractured well.
Formation Damage Caused by Improper Mn3O4-based Filter Cake Cleanup Treatments
Authors: Al Moajil Abdullah M. , Nasr-El-Din Hisham A. 
Published: June 2011

Abstract
Cleanup of filter cake is a difficult task and becomes more challenging when dealing with weighting materials such as manganese tetraoxide. Mn3O4 is a strong oxidizing agent and can be used as a catalyst due to its active phase, which will result in complex interactions with most cleaning fluids.
The reaction of selected organic acids and chelating agents with Mn3O4 particles as a function of time and temperature were studied. Atomic absorption was used to measure manganese concentrations and X-ray diffraction to analyze solids remaining after the reaction.
White precipitate of manganese citrate was produced following the reaction of citric acid with Mn3O4 up to temperatures of 284°F. The amount of precipitation increased with temperature and initial chelate concentration. GLDA reacted with Mn3O4 particles completely at 190°F. However, a large amount of white precipitation produced. Similarly, a white precipitation was observed with oxalic and tartaric acids. The reaction of DTPA with Mn3O4 particles in glass reactor produced Mn(silicates) at 212 and 284°F. This study will help drilling/completion engineers to avoid using such chemicals to prevent formation damage after filter cake removal treatments.
Mitigation of Fines Migration Using a New Clay Stabilizer: A Mechanistic Study
Authors: El-Monier I. A. , Nasr-El-Din H. A. 
Published: June 2011

Abstract
Fines migration is a well known problem in sandstone formations, where clay particles are released when come in contact with fresh water or high pH fluids. In its nature state, each clay platelets is surrounded by an atmosphere of cations. These positive charges neutralize the negative charges of the platelets and hold the platelets in electrostatic equilibrium. Beside the electrostatic interactions between colloidal entities, dispersion forces often called the London-van der Waals forces, which are always attraction forces, exist between particles. To mitigate the migration problem, it was required to control these forces.
A new inorganic Al/Zr-based clay stabilizer was used to mitigate fines migration problem. Its effectiveness was proven experimentally in Berea sandstone cores with permeability of 65–100 md, Berea sandstone is rich in kaolinite. It showed also great effectiveness when come in contact with high pH fluids. Coreflood tests were conducted at various temperatures up to 300°F. Effluent samples were collected, and the concentrations of different cations were measured using ICP.
Experimental results showed that the stabilizer was effective in mitigating fines migration in Berea cores up to 300°F. The amount of Al/Zr retained in the core effluent was found to be a function of clay content. Various forces acting on clay particles were defined using Derjaguin and Landau, Verwey and Overbeek theory. The mechanism of stabilizing clay using the new chemical is well explained by DLVO theory. The results of this work will help production engineers to design clay stabilizer treatment used in the field.
Measurement of Acid Placement with Temperature Profiles
Authors: Tan X. , Tabatabaei M. , Zhu D. , Hill A. D. 
Published: June 2011

Abstract
Optimum fluid placement is crucial for a successful acid stimulation treatment, both for horizontal wells where there is a broad variation of reservoir properties along the wellbore, and for vertical wells with multiple zones and/or extensive productive intervals. Recently, distributed temperature sensing technology has enabled us to observe dynamic temperature profiles along a wellbore during and after an acid treatment. This technology allows us to monitor and evaluate treatments in real-time by capturing a sequence of temperature profiles at different times and evaluating temperature response to acid injection.
We have developed mathematical models to simulate the temperature behavior along a wellbore, horizontal or vertical, during and shortly after an acid treatment. This approach couples a wellbore model and a near-wellbore thermal model considering the effects of both mass and heat transfer between the wellbore and the formation. The models account for all significant thermal processes involved during a treatment, including heat of reaction, conduction and convection. An inversion procedure is applied to interpret the acid distribution profiles from the measured temperature profiles.
For horizontal wells, the results indicate that the distribution of stimulation fluid along a lateral and the effectiveness of diversion processes during an acid treatment can be quantified in real-time using distributed temperature measurements. The model shows that the relative injectivities into different zones can be interpreted from the temperature response measured during injection. For vertical wells, we have focused on diagnosing the volume of acid placed in each zone from the flow back temperature history. During the flow back period, the zones that have taken more acid volume will show more heating because of reaction, and will have higher temperature when entering the wellbore. This provides a mechanism to quantitatively determine the acid distribution. The methods developed from this study can help to diagnose and optimize acidizing design, and improve the efficiency of acid stimulation.
Protect and then Inject: Optimized Well Fluids Successfully Drill Depleted Reservoirs to Store Gas
Authors: Vickers Stephen , Bruce Stephen , Hutton Alistair , Nunzi Paolo 
Published: June 2011

Abstract
A major operator has initiated the data acquisition campaign in the Southern North Sea for a future storage facility capable of holding 5 billion m3 of gas. It is estimated this venture will double the existing gas supplies stored in the UK and represent over 5% of its annual gas demand. As North Sea gas production decreases and the UK becomes more dependent on imports, the ability to store gas has become an important part of the UK energy policy.
Drilling into depleted reservoirs for gas storage produces several major technical problems and issues that must be addressed. This field is a pressure-depleted reservoir with a differential pressure equivalent to 7.3 lb/gal between the drilling fluid's hydrostatic pressure and the reservoir pressure. This differential must be controlled to eliminate the risk of differential sticking, downhole losses, and hole collapse.
Due to the reservoir depletion, it would be impossible to backflow and clean up the near-wellbore region without a post drill-in treatment fluid to remove the fluid filter cake and water-wet all the surfaces for gas injection. To ensure project success and usable fluid designs, reservoir conditions were simulated in the laboratory and fluid parameters were altered to provide the optimum properties to minimize the future risks.
The paper discusses in full the laboratory design process, the verification of the drill-in and treatment fluids as being fit-for-purpose, and their successful application in the field. Initial well testing suggested the expected injection rates of 500 scf/min at 300 psi were exceeded, with rates of 750 scf/min at 280 psi reported.
Modeling Non-Matrix Flow and Seals Integrity in Soft Sand Reservoirs
Authors: Onaisi Atef , Ochi Jalel , Mainguy Marc , Souillard Phillipe 
Published: June 2011

Abstract
Most of oil reservoirs operated by Total in West African deep offshore are multi layered highly unconsolidated sands. Burial depths, below the mud line, ranges from 500 to 2500mTVD. Sea water injection is done for pressure maintenance in deviated and horizontal wells equipped with sand control. Polymers injection for EOR and PWRI are also practiced.
In theory, the very high permeability of soft sand reservoirs should allow injecting in matrix mode at high rates with small differential pressure. In reality, declining injectivity over time requires injecting in non-matrix mode, at much higher pressures than anticipated, hence the concerns about the confinement of the injection. The mechanisms of injectivity restoration by increasing the pressure in soft sands and the subsequent risks of cap rock failure have to be understood. Their incorporation in modeling tools is crucial for predicting the operating pressure range and designing the surface and wells facilities accordingly. Standard tensile fracturing models commonly applied to consolidated reservoir rocks do not seem to be adapted to soft materials which behavior is dominated by shear failure and resulting in dilation. This paper will present modeling approaches aimed at predicting the responses of soft sands and of the cap rock to produced water injection taking into account the coupling between geomechanics, flow and formation damage. Field observations are presented and confronted with model predictions.
Selective Stimulation and Water Control in High-Water-Cut Wells: Case Histories from Upper Magdalena Valley Basin in Colombia
Authors: Rodriguez E. , Duarte C. , Martinez W. , León J. , Ortega A. , Lastre M. , Milne A. , Navarro C. 
Published: June 2011

Abstract
A brownfield located in the southwest region of Colombia, in the Upper Magdalena Valley Basin, produces from shallow marine sandstones of the Upper Cretaceous-aged Monserrate Formation. Net pay varies from 50 to 150 ft, with porosity between 17 and 22%, and permeability of 80 to 360 mD. The wells in this field, which has been under water injection since 1997, produce with a high water-cut, which in most cases exceeds 90%.
Water injection has led to inorganic scale, organic scale, asphaltene deposition, fines migration, and the need to treat the wells using hydraulic fracturing and/or matrix acidizing techniques. Conventional matrix stimulation treatments require the use of straddle packers to ensure complete zonal coverage and frequently result in increased water production with no significant increase in oil production, making the treatments uneconomical.
To reduce the cost of and increase the success rate of matrix treatments, a Combined Diverter and Conformance Control (CDCC) fluid was introduced. This allowed the stimulation to be performed when mechanical diversion was not possible due to wellbore restrictions. The CDCC fluid is pumped in alternating stages with the acid system to divert the treating fluid and provide water conformance control.
A recent stimulation campaign, using the CDCC fluid in this field, resulted in a 30% increase in oil production while reducing the water cut by 10%. The average cost of the treatments was reduced by 27%, when compared to conventional treatments. This has led to a reassessment of the economics of the field, with the possibility of recovering an additional ~3% of the reserves in place. The plan is to treat routinely underperforming wells, irrespective of the water cut.
The ability to increase economically the oil production in this marginal field has led to a reassessment of other similar fields approaching their economic limit.
Macrophage Deletion of SOCS1 Increases Sensitivity to LPS and Palmitic Acid and Results in Systemic Inflammation and Hepatic Insulin Resistance
Authors: Sachithanandan Nirupa , Graham Kate L. , Galic Sandra , Honeyman Jane E. , Fynch Stacey L. , Hewitt Kimberly A. , Steinberg Gregory R. , Kay Thomas W. 
Published: June 2011

OBJECTIVE
Macrophage secretion of proinflammatory cytokines contributes to the pathogenesis of obesity-related insulin resistance. An important regulator of inflammation is the suppressor of cytokine signaling-1 (SOCS1), which inhibits the JAK-STAT and toll-like receptor-4 (TLR4) pathways. Despite the reported role of SOCS1 in inhibiting insulin signaling, it is surprising that a SOCS1 polymorphism that increases SOCS1 promoter activity is associated with enhanced insulin sensitivity despite obesity. In the current study, we investigated the physiological role of myeloid and lymphoid cell SOCS1 in regulating inflammation and insulin sensitivity.

RESEARCH DESIGN AND METHODS
We used mice generated by crossing SOCS1 floxed mice with mice expressing Cre recombinase under the control of the LysM-Cre promoter (SOCS1 LysM-Cre). These mice have deletion of SOCS1 in macrophages and lymphocytes. We assessed macrophage inflammation using flow cytometry and serum cytokine levels using Bioplex assays. We then measured insulin sensitivity using glucose tolerance tests and the euglycemic-hyperinsulinemic clamp. Using bone marrow–derived macrophages, we tested the effects of SOCS1 deletion in regulating responses to the TLR4 ligands: lipopolysaccharide (LPS) and palmitic acid.

RESULTS
SOCS1 LysM-Cre mice had increased macrophage expression of CD11c, enhanced sensitivity to LPS, and palmitic acid and increased serum concentrations of tumor necrosis factor-α, interleukin-6, and monocyte chemoattractant protein. Increased inflammation was associated with impaired glucose tolerance and hyperinsulinemia as a result of reduced hepatic but not skeletal muscle insulin sensitivity.

CONCLUSIONS
The expression of SOCS1 in hematopoietic cells protects mice against systemic inflammation and hepatic insulin resistance potentially by inhibiting LPS and palmitate-induced TLR4 signaling in macrophages.