bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Approach for Formation Damage Control of Horizontal Drilling in High Permeability Sandstone Reservoirs
Authors: You Lijun , Kang Yili , Niu Xiao , Luo Faqiang , Gao Yuan , Liu Yanying 
Published: June 2013

Abstract
Due to usual higher oil and gas production, high permeable reservoirs are considered to be forgiving and to be able to hold up very well against formation damage induced by any solids and liquids, so these reservoirs have not deserved a fair share of that attention. In fact, any formation damage can inevitably alter the permeability of the porous media and adversely affect oil recovery to different degrees, and the damage is more deadly to horizontal well. Triassic reservoir with the maximum permeability of more than 2 Darcy and the maximum throat sizes of more than 100 μm in the Tarim Basin provides us with a perfect example. Horizontal well is the key technique to increase oil production in this reservoir. However, after completion, horizontal wells can not produce through natural power or gas-lift, and did not present the advantages of increasing production compared with vertical wells. The results of granularity analysis and dynamic damage evaluation experiments present that the original drill-in fluids can not protect the reservoir with permeability of more than 100 mD, while the percentage of regain permeability is less than 50%. The drilling fluids were modified by adding fibrous bridging agents instead of common spherical bridging agents to rapidly form a tight plugging zone near the wellbore that efficiently seals the large pore throats. The dynamic filtration test and the analysis of mudcake through the FEI Quanta 450 environment scanning electron microscope (ESEM) showed that the optimized drill-in fluids can form tight filter cakes, plug the pore of reservoir effectively, and enhance the percentage of regain permeability of core samples up to 90%. After the application of the new drill-in fluids, horizontal wells are in high flowing production after completion, and the wellbore quality are also improved.
Mechanical and Flow Behaviour of Collapsed Wellbores in Non-Compliant Sand Control Completions
Authors: Tovar J. , Noblett D. 
Published: June 2013

Abstract
In non-compliant sand control completions such as stand-alone-screens, the annular gap between the wellbore wall and the screen has always been considered detrimental to efficient inflow. They are typically associated with large skins resulting from the mixing of failed sand grains and the development of a new and continuously changing permeability as the collapsing material starts to compact onto the screen. Annular movement of sand grains and non-uniform bridging creating "hot" spots will eventually lead to erosion and completion failure. Previous researchers have investigated the change in permeability of failed rock into annular gaps generated in non-compliant sand control completions and identified that packed material in this space can result in severe distortion to flow patterns and restrictions.
This paper describes the mechanical and flow process occurring as the wellbore wall collapses onto the screen surface. Constitutive models are used to characterise the mechanical behaviour of the failed material in terms of deformation and collapse of the near wellbore onto the screen. Continuous (foot-by-foot) inflow models are presented to illustrate the impact of the deformation process as the annular gap is filled up on inflow. A detailed laboratory testing program and its results are presented to validate both processes using samples from North Sea sandstone reservoirs. The results indicate that for non-compliant sandface completions such as stand-alone screens, it is possible to determine whether the collapse of the wellbore will occur and how productivity will be affected. From the mechanical point of view the rock follows an extension-dilatancy-compaction path. This will at the same time produce a varying permeability and hence inflow, the magnitude of which will depend on factors such as pore pressure, drawdown pressures, reservoir rock mechanical properties and mineral composition. This extensive testing program has led to the development of a series of analytical models, testing procedures and design methodologies for wells being completed with non-compliant sand control completions.
Development And Implementation Of Low Density, Water-Based Reservoir Drilling Fluid. Case History From The Troll Field In Norway
Authors: Fjogstad Arild , Hage Ingebjørg , Svanes Grete 
Published: June 2013

Abstract
The Troll field in Norway is a large gas field with a thin oil column. The thin oil column requires the wells to be drilled as long horizontal oil producers and development of the field has relied entirely on water based drilling fluids. As the pressure in the reservoir is depleting there is a requirement to reduce the density of the drilling fluid used to avoid losses. The latest development that is described in this paper is the design and implementation of a reservoir drill-in fluid with a maximum density of 1,07 SG, which at the same time maintains all the technical requirements necessary to avoid formation damage. The laboratory evaluation and verification was performed together with the operator to ensure no operational problems arose from changing to a new system. New technology was introduced to allow for clay inhibition without the use of salt to reduce the density of the base fluid. Bridging was optimized to match the requirements for the high permeability reservoir with minimum concentrations of solids. Product selection was driven by the need to ensure minimum formation damage. The initial field trial and the resulting implementation on subsequent wells and different rigs are described. The difference in performance related to other types drilling fluid systems is discussed. In addition, the effect of the differences in solids control equipment and storage capacity on different rigs is evaluated.
Produced Water Re-Injection Design and Uncertainties Assessment
Authors: Ochi Jalel , Dexheimer Dominique , Corpel Vincent 
Published: June 2013

Abstract
Produced water re-injection (PWRI) is an important strategy for deriving value from waste water but its implementation can face challenges related to injectivity and safety issues. Re-injection in fracturing regime is often the only option to guarantee the sustainability of injectivity but it can present some risks to be anticipated early during the design phase.
The first objective of a PWRI design study is to supply water quality specifications to petroleum architects (in terms of solid and oil contents) to allow designing water treatment facilities. The second objective is to supply injection pressure specifications allowing designing injection pumps and network. These specifications must allow sustaining well injectivity over field life while preventing any risk of cap rock failure.
The specification of water quality is of prime importance as a maximum of contaminant injection is sought in order to minimize the cost related to water treatment, but at the same time it must prevent any injectivity loss or excessive increase of pressure beyond which fracture confinement is no more possible.
Water quality and injection pressure are thus linked to each other. They are deduced by simulation on a case by case basis. The modeling approach used by Total was presented in previous publications. The objective of this paper is to detail how the two parameters are deduced when uncertainties on input data are considered. Indeed, a workflow for uncertainty management based on experimental design and Monte Carlo theories was implemented to combine the simultaneous effect of a relatively large number of uncertain parameters, each of them being characterized by its own probabilistic distribution. Two thousand simulations are systematically run and water quality as well as injection pressure specifications are supplied with a probabilistic value (P10, P50 and P90).
Application of this approach to real design examples are detailed and discussed in this paper.
Development of Volumetric Horizontal Well Stimulation Model
Authors: Nwoke Linus A. 
Published: June 2013

Abstract
The knowledge of damage profile in horizontal wells is the key to designing the appropriate treatment volume to restore or improve their productivities. The elliptical (conic) damage profile associated with horizontal well is known but review of industry-wide applications by different Operators shows no corresponding uniform correlation between the damage profile and actual treatment volumes that have been applied. The result of this inadequacy has often led to sub-optimal post stimulation performances due to either partial damage removal or formation deconsolidation as a result of little or too much acid volumes across the damaged zones that could lead to poor coverage or over-dose with attendant incomplete damage removal or secondary precipitates respectively. Funds spent on stimulating horizontal wells estimated at average of USD 0.5mln/well did not yield the expected rewards as the stimulation gains are mostly short-lived due to wrong volume design and application.
The problem highlighted above led to the emergence of this engineering model based on the complete knowledge of elliptical horizontal damage profile usually associated with horizontal completions and is presented for improved stimulation solution to the removal of damage in horizontal wells. The approach offers true stimulation in cost effective manner by applying only the right acid volume in the right zone of interest.
The development of the horizontal well stimulation model from the first principle and presentation of easy-to-read table and charts for specific range of well parameters (damage radius, porosity, wellbore radius and drain-hole length/diameter) versus treatment volumes, field applications guide, limitations and costs/treatment benefits are the output derivable from this innovative work.
The benefit of this emerging technology includes; reduction in cost of chemical for well treatment, true stimulation of damaged near-wellbore region and improved performance, minimal contact of acid system to downhole tubular and overall cost efficiency estimated at 50% savings when compared with existing approach that uses about 200% of the required acid volume.
Decreasing Formation Damage with New Completion Methods in Daqing Oilfield
Authors: Zhu Guowen , Sui Xinguang , Liu Bing , Xu Bo , Wang Mingsheng , Xiang Weiqing , Liu Lihong 
Published: June 2013

Abstract
Daqing Oilfield is a continental deposit oilfield with multi-layers. It has entered a high water cut development stage, its tertiary infill wells mainly develop the formations with effective thickness less than 0.5m and a low permeability less than 0.05 Darcy, this kind of layers usually perform a low conductivity. Technically, this formation requires a better completion method. Being previously used on high permeability formation with small aperture and short penetration, the perforating bullet could not meet the completion requirement in such a low permeability formation. At present, new type of perforating bullets are being developed with aperture and penetration of 1.5 fold respectively, but its high perforating energy make a thicker compacted zone around the penetrated channel, this result in a low conductivity.
This paper discusses about this problem, by applying new completion methods to reduce the formation damage in low permeable reservoir. First, the negative pressure perforation method is applied to reduce the stemming; second, a compound high energy perforation method is applied to perform about 10cm length fissures which can penetrates the compacted zone around the channel thus increase the conductivity. Both of the two methods were applied combined on 166 tertiary infill wells in 2011, it increased a fluid productivity to 2.8t/d.m, it was 2.9 folds of the previous perforation. It effectively solved the problem of formation damage caused by deep penetration bullet to highly increase the fluid productivity in low permeable reservoir.
Surfactant-Based Fluid-Loss Pills for ZnBr2-Based High-Density Completion Fluids and High-Temperature Applications
Authors: Gomaa Ahmed M. , Cutler Jennifer , Qu Qi , Cawiezel Kay E. 
Published: June 2013

Abstract
Excessive loss of high-density brines into the formation has always been a major concern during completion operations, since it is uneconomical and leads to formation damage and well control issues. A viscoelastic surfactant (VES) system was introduced as an alternative for polymers because of high-temperature instability, incompatibility problems, and the necessity of acid cleanup for the polymer-based system. However, past literature documented that VES systems were limited to only CaCl2/CaBr2 brines due to the negative effect of ZnBr2 solutions on the surfactant's ability to form gel which limits the applicable density for past fluid-loss pills. This paper introduces improved fluid technology that uses nanoparticles and new low molecular weight surfactants to effectively control fluid-losses for high-density brine that contains ZnBr2 at high temperature application.
Laboratory studies were conducted to examine the effect of the VES system on controlling leak-off rate using a HP/HT fluid-loss cell. The apparent viscosity of the VES solution was measured as a function of shear rate and temperature (up to 300°F).
Based on experimental results leak-off of surfactant based fluid is controlled by the elastic structure of the surfactant micelles. The strong elastic structure of gel will not deform to pass through the pores, it will plug this pores and eliminate any flow of the solution. Therefore, surfactant-based pill developed long-term stability as it tested for 7 days with a noticeable decrease in the leak-off rate with time. Optimum surfactant concentration does not depend on the brine composition or formation permeability but it was mainly dependent on temperature.
A breaker based on mineral oil caused a smooth viscosity decline while a breaker based on mutual solvent had a rapid viscosity decline. For mutual solvent, viscosity was instantaneously reduced by 50 to 90% depending on brine composition, surfactant concentration and temperature. However, temperature has most significant effect.
An Effective Single-Stage Acid System for Sandstone Formations
Authors: Gomaa Ahmed M. , Cutler Jennifer , Qu Qi , Boles Joel , Wang Xiaolan 
Published: June 2013

Abstract
Sandstone acid systems, which are composed of HCl and HF, are commonly used to remove the formation damage in sandstone reservoirs. However, to perform any treatment using these acid systems, a preflush and/or a postflush of HCl plain acid must be injected to eliminate CaF2 precipitation and secondary precipitation. In this study, a new sandstone acid formulation was developed that can be used as a single stage sandstone acid system. This system eliminates the requirement of preflush and postflush HCl acid stages, reduces the treatment complexity, reduces the HCl requirements, and reduces the overall treatment/rig time.
A coreflood study was conducted using different sandstone cores at 180°F. In additional to quartz, the tested cores had varying amounts of clay mineral, feldspar, and carbonate. Consequently, they can be used to judge the performance of the new acid system.
Based on the experimental results, regular sandstone acid must be used with a preflush stage of HCl acid to maximize its performance and eliminate CaF2/MgF2 precipitation. The needs of the postflush stage must be confirmed as it can cause damage for sandstone that has HCl-sensitive clay mineral. All selected single-stage sandstone acid formulations (Acids A, B, C, and D) were able to successfully treat Bandera sandstone cores. For Bandera sandstone cores, increasing HCl/HF ratio increased the permeability enhancement and reduced the injected acid volume. Using the same acid volume and composition, a higher permeability enhancement was observed for the core that had less clay and carbonate content. Based on HCl:HF ratio and sandstone composition, a minimum acid volume is required to achieve a permeability enhancement. For the Bandera sandstone formation, only 8 pore volumes of the new acid system was required to achieve 26% permeability enhancement. However, for a Berea sandstone core that had less clay mineral, 4 pore volumes of the new acid system increased the permeability by 86%. The feldspar amount in the composition of sandstone can significantly impact the permeability enhancement of Acid C, while kaolinite amount has nearly no effect. A corrosion test was conducted at 180°F for 6 hr using a two pipe grades (Cr-13 and N-80). Two types of corrosion inhibitor were evaluated at different concentrations. All tested formulas had a very low corrosion rate (less than 0.03 lb/ft2). For both corrosion inhibitor types, corrosion rate was increased by reducing the HCl/HF ratio and/or inhibitor concentration.
The Long-Term Production Performance of Deep HPHT Gas Condensate Fields Developed Using Formate Brines
Authors: Olsvik Gunnar , Howard Siv , Downs John 
Published: June 2013

Abstract
Formate brines have been in use since 1995 as non-damaging drill-in and completion fluids for deep HPHT gas condensate field developments. The number of HPHT fields developed using formate brines now totals more than 40, and includes some of the deepest, hottest and highly-pressured reservoirs in the North Sea. The well completions have been both open-hole and cased-hole.
An expectation from using formate brines as reservoir drill-in and completion fluids is that they will cause minimal damage to the reservoir and help wells to deliver their full productive potential over the life-time of the field. The validity of this expectation has been tested by examining the long-term hydrocarbon production profiles of eight HPHT gas condensate fields in the North Sea where only formate brines have been used as the well completion fluids. In five of these fields the wells were drilled with oil-based muds and completed by perforating in cased hole with high-density formate brines. In another two of the fields the wells were drilled with formate brines and completed with screens entirely in open hole using the same brines. The last of the eight fields was drilled with formate brine and the wells were then completed with same fluid in either open hole or cased hole.
The results of the production analysis provide a unique insight into the impact of a single type of specialist drill-in and completion fluid on the rate of recovery of hydrocarbon reserves from deeply-buried reservoirs in the North Sea.
A 20/80 Oil/Water Ratio Nonaqueous Screen Running System Successfully Employed In Equatorial Guinea
Authors: Paz Luis , Lim Sooi Kim , Patel Arvind , Luyster Mark , Ravitz Ray 
Published: June 2013

Abstract
An innovative surfactant chemistry in a nonaqueous system with an oil-to-water ratio (OWR) of 20/80 was effectively utilized for the first time to provide wellbore stability and run a sand-control screen in an openhole gravelpack completion. This novel type of invert emulsion system uses relatively higher aqueous internal phase, i.e., less than 50/50 OWR, which subsequently allows for a relatively higher density than the drilling fluid. More importantly this system is maintained as solids free and oil continuous.
The increasing application of Inflow Control Devices/Intelligent Wellbore Systems and swellable elastomers as well as drilling longer intervals and their exposure to shale/sand dictates the use of compatible and solids-reduced invert systems to reduce the risk of an unsuccessful gravel placement treatment caused by shale swelling or plugging of sand control screens. This novel high-internal phase system provides flexibility for these types of completions. The use of the higher internal phase allows the formulation of oil-continuous solids-free systems while still achieving the required density necessary in solids-laden aqueous systems. This paper will focus on the selection of the 20/80 high-internal-phase system for this openhole completion, the upfront testing and planning for deployment. Discussion will also be provided with respect to the mixing of the system at the wellsite as well as the lessons learned.
Characterizing Formation Damages Due to Carbon Dioxide Injection in High Temperature Reservoirs and Determining the Effect of Solid Precipitation and Permeability Reduction on Oil Production
Authors: Khurshid Ilyas , Choe Jonggeun 
Published: June 2013

Abstract
Carbon dioxide injection and its performance during sequestration activities rely on the ability of the injection well to inject the desired amount of CO2 for decades. However, the CO2-rock-water interaction may cause immense formation damage by plugging the pores and reducing the permeability. Its severe consequences will reduce oil and gas productivity and CO2 injectivity in the reservoir. In this study a numerical simulator is developed and it solves the fluid flow equations, chemical reactivity equations, particle transport and particles deposition equations to predict the amount of formation damage during CO2 injection. We found that it has high rate of chemical reactivity and dissolution of reservoir rock near the wellbore. The dissoluted reservoir rock particles get precipitated in the reservoir away from the injection well, plugging the pores and reducing the formation permeability.
From the simulation result on the effect of reservoir depth and temperature, we found that deep oil and gas reservoirs are good candidates for CO2 sequestration than shallow reservoirs. Because the increased depth and temperature of a deep reservoir decrease the CO2 dissolution rate and lower the solid precipitation. Sensitivity analysis of CO2 injection rates was performed to identify the effect of CO2 injection rate on reduced permeability in deep and high temperature formations. It was found that increased CO2 injection rates and pressures enable to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO2 at a higher rate for better pressure maintenance, no further diminution of residual oil.
The Influence of Wettability on Return Permeability
Authors: Viste P. , Watson R. B. , Nelson A. C. , SWACO M-I 
Published: June 2013

Abstract
Many return permeability tests are performed with extremely water-wet cores. This is a result of using outcrop core or solvent-cleaned reservoir core. Core is often prepared to a similar liquid saturation as in the reservoir with a matching viscosity mineral oil as a substitute for the main reservoir production phase. As a result the core remains in a water-wet condition. Exposing highly water-wet rock to an oil-based filtrate has the ability to alter mineral surface wettability due to the presence of emulsifiers. The subsequent reduction in permeability can be interpreted as damage, although there is uncertainty that such reduction would take place if the wettability was correct at the start of the test. The pass criteria for drilling fluids are often set as a minimum percentage return permeability. Unrepresentatively high wettability alteration in the laboratory may lead to wrong conclusions.
This paper presents data and observations which display the differences between the use of water-wet and mixed-wet, aged core and the impact on return permeability results. Return permeability results are presented by allowing cores to naturally alter wettability in the presence of reservoir fluids prior to the exposure of oil-based drilling fluids. These data are presented in comparison to duplicate tests on strongly water-wet cores. The difference in return permeability results when comparing the two start conditions is significant.