bluuebunny/crossref_metadata_2025 huggingface dataset:
Influence of Tensile Strength and Production Effects on Hydraulic Fracturing in Low Porosity Carbonates: The South Arne Case
Authors: Vejbæk Ole V. , Jakobsen Erik , Lamb Ricky , Troelsen Benny , Bazan Lucas W. , Brown Eric K. , Tran Phi , Meyer Bruce R.
Published: June 2013

Well planning in mature fields can be challenging as the more marginal reserves are targeted. Hydraulic fracture stimulation is a key technology to access multiple reservoir layers and thereby maximize recovery. However, fracture propagation in low porosity carbonates may be strongly confined because of high tensile strengths in bounding layers. The strong confinement can impede vertical fracture propagation and the ability to access reservoir units adjacent to the initiation interval. Understanding vertical hydraulic fracture growth through low porosity layers improves the hydraulic fracture design, enhances reservoir deliverability potential and enables the identification of infill well potential and intervention opportunities.

The South Arne field is located in the northern part of the Danish sector of the North Sea. The Tor and Ekofisk formations are high porosity/low permeability chalks with low to moderate natural fracturing. Porosities may reach 45%, but a hard low porosity interval of 10% or less at the bottom of the Ekofisk formation separates and partially compartmentalizes (horizontally) the two formations. A series of indirect tensile strength measurements on South Arne cores were conducted. The measurements verified a suspected exponential increase in tensile strength at low porosities, essentially causing the tensile strength to exceed 1,500 psi in some cases.

Recent 4D seismic surveys have enabled separate sweep patterns for each reservoir unit to be mapped and indicate that the sweep is much less efficient in the Ekofisk. This supports that the hydraulic fracture stimulation treatments initiated in the Tor formation are not accessing the upper units to the degree previously assumed and it appears that connection is occurring via pre-existing faults and/or natural fractures. The hydraulic fractures propagate nearly longitudinal to the wellbore, guided by regional stresses, with limited height growth. However, production effects, specifically compaction induced by draw down, may perturb the stress field sufficiently so that the preferred alignment is not achieved, further reducing sweep efficiency. This is indicated by 3D coupled geomechanical modeling and is corroborated by 4D seismic observations.
Particle Size Analysis For Sand Control Applications
Authors: Ballard Tracey , Beare Steve
Published: June 2013

Sand screen selection relies on accurate particle size information for the sands that need to be controlled. Within the oil industry there is awareness of the differences between dry sieve analysis and laser particle size analysis (LPSA), but there can also be wide variations between LPSA performed in different laboratories even when such variables as sample preparation are taken into consideration. Recent work by the authors has shown that such variables as sonication time and amplitude can have a significant effect on certain sands, and there is evidence to indicate that the sensitivity to sonication is dependent on the mineralogy of the sand. Other factors have also been examined to address the widespread view within the oil industry that LPSA exaggerates the fines content, whereas the opposite view is held in sedimentology and soil science in that the coarse fraction is believed to dominate. Work has been performed to examine which view might be most relevant for reservoir sands, and guidelines for performing LPSA are proposed.
Productivity Improvement in Highly Unconsolidated Formation: Skin Characterization and Mitigation, Case History
Authors: Lastre M. , Milne A. , Pinto C.
Published: June 2013

The productivity of highly permeable and unconsolidated sandstone reservoirs is expected to be high; however, the production seldom meets expectation as these reservoirs are more sensitive to the formation damage from the drilling and completion of the well.

There are extensive publications regarding characterization and identification of formation damage and the total final skin of thick unconsolidated oil reservoirs, with or without sand control (Okoye et al., 1992; Benion et al., 1994). However, many of the currently producing unconsolidated reservoirs are thin formations, with poor defined barriers producing heavy oil with a high water cut and sand production.

To optimize productivity in wells completed in multiple thin highly permeable sands it has proved necessary to develop a new completion optimization methodology. The methodology accounts for formation damage mechanisms and mechanical skin factors - completion, perforation and non-Darcy effects - to select the optimum production strategy and final completion, including sand control.

The completion optimization methodology can also be applied to existing wells to identify the factors limiting productivity and so evaluate the technical and economic of alternative remedial actions.

The methodology was applied in one field with 15 wells completed with gravel pack completions in thin laminated sandstone reservoirs ranging in height from 4 to 15ft. producing intermediate crude with an average rate of 2000 BFPD, despite a high positive skin. Initially the skin was attributed to formation damage - fines and scaling. However, the damage was correctly determined to be due to non-Darcy flow due to inadequate sand control. Recompleting these wells and changing the production strategy the final skin was reduced by an average of 60% and production increased by 35%. The completion optimization methodology has proved to be a versatile means of optimizing production in a number of different fields with wells completed in a number of thin highly permeable sands, producing intermediate crude and water.
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

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

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

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

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

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

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

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

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

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

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

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

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.
A New Diversion Technique to Remove the Formation Damage from Maximum Reservoir Contact and Extended Reach Wells in Sandstone Reservoirs
Authors: Ba Geri B. S. , Mahmoud M. A.
Published: June 2013

Maximum reservoir contact and extended reach wells have been widely used to maximize the well productivity. The horizontal section could be 6000 ft or more in those wells, which make the damage caused by the drilling fluid varied from one section to another in the long horizontal section. The process of diversion of the stimulation fluid in carbonate wells with the same features has been performed using Viscoelastic surfactant (VES) and polymers based hydrochloric acids. In sandstone wells we cannot use either VES or polymers because there is no enough calcite to react with these fluids to produce the gel diverting materials. Also, VES could be adsorbed on the sandstone surface and cause more damage to the formation, and the use of HCl in sandstone formations has been proved to be more damaging than removing the damage.

In this paper we will introduce a smart fluid that can be used to remove the damage caused by calcium carbonated weighted drilling fluid from the maximum reservoir contact (MRC) and extended reach wells without adding any gelling materials. This fluid will react with carbonates in the sandstone formation and will produce high viscosity that will divert the flow through the less permeable part in the horizontal sections. The proposed fluid is HEDTA (hydroxyl ethylene diamine tri acetic acid). Sandstone cores were used in the coreflooding experiments, and the stimulation fluid viscosity will be measured before and after the flooding. Parallel coreflooding technique was used to confirm the diversion ability of this chemical through two sandstone cores with different permeabilities.

The experimental results showed that the viscosity of the stimulation fluid increases at least 3 times after the treatment of the sandstone cores and the parallel coreflooding showed a good ability of diversion for the fluid. The experimental results were used to describe the process of diversion using this fluid mathematically in this. HEDTA chelating agent showed good ability to remove the damage caused by drilling fluid from different permeability contrast set of cores.
The Effect of Different Brine Solutions on the Viscosity of VES Micelles
Authors: Gurluk Merve R. , Wang Guanqun , Nasr-El-Din Hisham A. , Crews James
Published: June 2013

Viscoelastic surfactants can provide viscoelastic properties in brines at high temperatures (higher than 230°F). Recent studies have shown the advantages of use nanoparticles in VES fluid systems. The nanoparticles have large surface area as well as unique surface morphology and surface reactivity. They can strengthen the micelle-micelle interactions. A small concentration of these particles can maintain viscosity at higher temperatures (up to 300°F) and decrease the rate of VES fluid leakoff (Huang, Crews and Willingham, 2008).

The viscoelasticity of nanoparticle-networked VES fluid systems was analyzed with a HP/HT viscometer. A series of rheology experiments have been performed by using 4 vol% amidoamine oxide surfactant in KCl, NaCl and CaBr2 brines at temperatures up to 275°F and a shear rate of 10 s-1. The nanoparticles evaluated were MgO and ZnO at the concentration of 6 pptg. In addition, the effect of different nanoparticle concentrations (0.5 to 10 pptg) on the viscosity of VES fluid was investigated. The oscillatory shear rate sweep (100 to 1 s-1) was performed from 100 to 200°F. The effect of an internal breaker on the viscosity of VES micelles was examined.
Formation Damage and the Importance of a Rigorous Diagnostic: a Case History in Nigeria Deep Water
Authors: Furgier Jean-Noël , Lebecq Cédric , Degos Xavier , Martin Frédéric
Published: June 2013

Total operate a field located 150 kilometers off the Niger Delta at a water depth of 1,400 meters. This field is the first deep-offshore development involving light oil with high gas content. In the field's Miocene reservoir the fluid is under saturated (~ 80 bar) and in ‘critical conditions’, i.e. the gas and liquid hydrocarbons are in a single phase, at high pressure and temperature.

Several turbiditic-type reservoir layers are developed with 22 oil producer wells, 20 water injector wells and 2 gas injector wells.

Reservoir G is a lobe sand body with good petro-physical characteristics (Permeability = 300 to 500 mD, Porosity ~ 20%). This reservoir is developed with 2 producer wells, well 7 and well 9, completed with frac-packs, and 2 water injector wells for pressure maintenance.

In September 2009, six months after first oil, well 7 and well 9 lost 70% of their potential following the decline of their productivity index. The impact was 20,000 bpd production shortfall.

This paper describes the investigation process that was conducted to identify the cause of the decline. The process included pressure transient analysis, geochemical analysis, core flooding tests and scale modeling. A trial and error approach was adopted when designing well intervention in order to get as much information as possible and firm up the most realistic cause of production damage.

This paper also highlights the fact that a proper diagnostic requires a multi-discipline approach, an open mind and a comprehensive risk analysis.
Stand Alone Screens: What Key Parameters are Really Important for a Successful Design?
Authors: Furgier Jean-Noël , Viguerie Bjorn , Aubry Eric , Rivet Pascal
Published: June 2013

Stand alone screens is a sand control technique that has been widely used in the industry for many years. However, some failures have been experienced, raising some concerns about the validity of design and operating procedures. Contrary to gravel pack for which Saucier criteria is well accepted, design criteria for a sand screen only has always been subject to discussion. As it is a simple and cost effective sand control solution, there is still an incentive to develop more robust design and installation rules.

Within Total, a large experience was built in running stand alone screens that allowed optimizing installation practices. In addition, a multi-year laboratory experiments program was run to establish the key parameters in designing stand alone screens. Results of this work are discussed in this paper.

First, an experimental work flow was developed and made reliable after evaluating consistence and repeatability of results.

Then, a sizing criteria based on the retention of the largest sand grains was confirmed to be pertinent.

At last, it was demonstrated the sand size distribution does not have any impact on the sand retention performance of a screen. It cannot be the origin of screen plugging.

This work will set new standards in stand alone screen design in Total.
Development and Applications of an Aqueous-Based Surface Modification Agent
Authors: Vo L. K. , Nguyen P. D. , Weaver J. D.
Published: June 2013

Surface modification agents (SMAs) were developed more than fifteen years ago to agglomerate proppant to reduce proppant flowback, prevent fines invasion and migration, and improve fracture conductivity. The instant onset of extreme tackiness and insolubility of SMAs can present operational challenges with respect to maintaining and cleaning fracturing equipment. This paper presents the laboratory development and field implementation of a new, aqueous-based surface modification agent (ASMA) that addresses operational challenges and provides superior economic benefits with low health and environmental risk. New potential uses resulting from slow onset of tackiness are also presented.

An ASMA is a water external emulsion having an SMA contained within the internal phase. This ASMA is applicable for all of the same uses as solvent-based SMAs, such as on-the-fly coating of proppant during fracturing, frac-packing, or gravel-packing. One new application made possible by emulsion delivery is the inclusion of the ASMA in the first fluid injected into a fracture, which coats the fracture face with a hydrophobic film. This film provides stability to soft formations, inhibits water invasion, minimizes damage attributed to formation spalling, and improves proppant distribution by causing proppant to adhere to the frac face.

ASMA is aqueous based, and can be diluted in brine for deep injection into existing proppant packs. This enables its use for remedial treatments to repair fines-damaged frac-packs where frequent acid treatments are required to maintain acceptable production. Laboratory optimization of acid stimulation and remedial fines-control treatment designs are presented.

New emulsion technology allows SMA release to be delayed so that the extreme tackiness and insolubility does not damage mixing equipment, and can be easily cleaned. In addition, the delayed delivery of the SMA permits direct injection into proppant packs and the formation matrix to provide for remedial fines treatments, resulting in longer lasting acid stimulation of frac-pack completions.
Viscoelastic Evaluation of Gemini Surfactant Gel for Hydraulic Fracturing
Authors: Yang Jiang , Guan Baoshan , Lu Yongjun , Cui Weixiang , Qiu Xiaohui , Yang Zhen , Qin Wenlong
Published: June 2013

The viscoelastic surfactant (VES) fluids have been used in stimulation of low permeability oil and gas reservoir due to their low formation damage. The physical association and entanglement of wormlike like micelle gives viscoelastic properties, which gives similar properties as polymer. However, conventional viscoelastic surfactant fluids were used at much higher concentration than that of traditional polymer guar fluids. The more effective VES fluids that performed at lower concentration are unmet needs to be filled. Hence, new cationic Gemini viscoelastic surfactants with connecting spacer were studied. The Gemini surfactants have higher surface activity than that of conventional surfactants. Critical micelle concentration of Gemini surfactants is 10 times lower than that of conventional surfactants. Fluids of Gemini surfactants gave the desired viscosity by forming gel structure at lower concentration than that of conventional surfactants. The viscosity of new Gemini VES fluid can be maintained above 50 cps at 1% under 120 °C and shear rate of 100 s-1. The fluid is shear stable at the temperature for 2 hours. The dynamic rheological properties of the new VES fluid showed highly elastic properties, which elastic moduli G’ is higher than loss moduli G’ ‘at angular frequency 0.1 rad/s below 100 °C. It showed good proppant suspending properties. The solvent with high polarity has less effect on fluid viscosity than that of solvent with low polarity. The Gemini VES gel can be broken down upon contacting and mixing with hydrocarbons or dilution with formation brine. The Gemini VES gel is a better alterative fluid for low damaging hydraulic fracturing.
Experimental Investigation on the Effects of Very Low Salinity on Middle Eastern Sandstone Corefloods
Authors: Pingo-Almada M. B. , Pieterse S. G. , Marcelis A. H. , van Haasterecht M. J. , Brussee N. J. , van der Linde H. A.
Published: June 2013

Low salinity flooding (LSF)- decreasing ionic strength to enhance oil production- is an Enhanced Oil Recovery (EOR) process currently being evaluated in industry and academia with first deployment beginning. A wettability modification is assumed to take place when decreasing the ionic strength. In this work we explore the effects of varying salinities from formation water down to very low salinity on brine permeability and on effluent composition. The following effects have been investigated: the presence and absence of oil in the core, the cation exchange capacity (CEC), mineral dissolution and cation stripping. The experimental component of this investigation consisted of continuous permeability measurements during flooding at various salinity steps and simultaneous collection of the effluent. The effluent was analyzed using Inductively Coupled Plasma (ICP elemental analysis). The CEC's of the rock exposed to the different salinities have also been measured. Scanning Electron Microscope (SEM) visual investigations have also been carried out.

During the flooding with several different brines, permeability variations were observed. The variation of the ionic composition of the effluent has allowed for:

identification and characterization of the temporary divalent cation stripping process the framing of hypotheses about other possible mechanisms taking place in the core during LSF, such as: ○ion exchange between injected brine and the clays as the salinity decreased○The role that CEC plays in the re-equilibration with the new salinity○the CEC variation throughout the experiment at Sor○mineral dissolution and clay deflocculation. The comprehensive suite of tools and techniques used here has given more insights into the mechanisms taking place when decreasing the ionic strength and their use can serve to improve the deployment of the technology, including the prevention of formation damage.
Using Hydrochloric Acid to Remove Ilmenite Water-Based Filter Cake in HPHT Applications
Authors: Elkatatny S. M. , Xiao J. , Nasr-El-Din H. A. , Al-Bagoury M.
Published: June 2013

The growing demand for well-designed weighting agents to overcome the currently drilling challenges such as ECD management and the settling tendency of the weighting agents led to the development of a new micronized ilmenite (FeTiO3). The acid solubility of ilmenite is of great importance to remediate any damage that might occur during its use in the drilling operation.

Extensive lab work was conducted to: 1) assess the reaction of 10 wt% HCl with ilmenite particles at 300°F and 300 psi using an aging cell, 2) optimize the concentration of HCl to remove the filter cake using a modified HPHT filter press at 250°F, 3) determine the removal efficiency of the filter cake, and 4) calculate the retained permeability of Indiana limestone cores.

The reaction of hydrochloric acid with ilmenite showed that HCl (10 wt%) dissolved 75 wt% of the iron from ilmenite particles after 10 hrs of reaction at 300°F. SEM and XRD results showed that the reaction product was mainly rutile (TiO2) after 6 hrs of reaction.

Ilmenite-based filter cake was removed completely after reaction with 5 wt% HCl (300 g solution) for 16 hrs soaking time at 250°F. The retained permeability of the Indiana limestone and Berea sandstone cores was nearly 100% after HCl treatment (5 wt%). Removal of ilmenite water-based filter cake is a simple process as compared with barite water-based filter cake, which cannot be removed using HCl. This study will provide a complete evaluation of the reaction of HCl with ilmenite and will help the drilling and completion engineers to better design the chemical treatments to remove the filter cake for HPHT wells.
Evaluation of Micronized Ilmenite as a Weighting Material in Oil-based Drilling Fluids for HPHT Applications
Authors: Xiao J. , Nasr-El-Din H. A. , Al-Bagoury M.
Published: June 2013

Ilmenite (FeTiO3) with a mean particle size of 30 – 45 um was first introduced into the oil industry as weighting material in 1976. However, its use was limited mainly because of its abrasiveness to drilling equipment. Recently, a superfine ilmenite (5 μm) was introduced to address shortcomings of the traditional weighting materials. The objective of this study is to discuss the performance of oil-based drilling fluids using ilmenite as a weighting material for HPHT applications.

Oil-based drilling fluids with a density of 1.92 SG containing API standard barite and ilmenite were compared. HPHT filtration tests under static and dynamic conditions were conducted at 300°F and 300 psi. Indiana limestone cores with an average porosity of 23 vol% and an average permeability of 100 md were used in the filtration tests. The rheological properties, sag tendency, the volume of filtrate, and the filter cake thickness of the oil-based drilling fluids were determined before and after heating at 400°F for 16 hours.

Results showed that ilmenite-based drilling fluids had a sag factor of < 0.3 and a plastic viscosity of 25–30 cp, much lower than those of barite. HTHP filtration tests showed that under static conditions, the filter cake had a thickness of 0.18 in. and 2.9 cm3 of filtrate volume; while under dynamic conditions, the filter cake thickness was 0.15 in. and the filtrate volume was 2.2 cm3. The rheological properties of oil-based drilling fluids were constant after heating at 400°F for 16 hours. The filter cake thickness and sag factor were small even after 16 hours of heating. This study provides an evaluation of oil-based drilling fluids with ilmenite as a weighting material for HPHT wells, and gives recommendations on how to use it in the field.