Formation Damage In Reservoirs Research Articles

An experimental study of alcohol injection to mitigate water blockage in commingled layered reservoirs

This study explores the effectiveness of alcohol injection as a stimulation treatment to mitigate water blockage in the vicinity of the wellbore. Over the years, water blockage has emerged as a recurring challenge within the oil and gas industry, leading to diminished well productivity.In a commingled reservoir with multiple layers, when a producing well is shut-in for well intervention or workover, water may encroach from water zones into the oil-bearing formations through the wellbore due to pressure differences between the layers. Water encroachment can have a significant impact on the production of a well. It can reduce the oil production rate, increase the water cut, and shorten the well's lifespan. Therefore, it is essential to take steps to mitigate the water encroachment effect in commingled reservoirs. This study explores the use of alcohol injection to reduce transition time and remediate formation damage in commingled oil reservoirs. Limited studies have shown that alcohol has the potential to enhance fluid relative Permeability in gas condensate reservoirs and reduce condensate banking near the wellbore. However, this approach has not yet been tested in commingled oil reservoirs.A series of core flooding tests were conducted using Berea sandstone cores and a Texan light crude oil sample. The core flood setup was designed to represent the water blockage condition in the formation. Two different alcohols were tested: isopropyl alcohol (IPA) and Methanol. Experimental results showed that mutual solvents significantly reduce water blockage and shorten the transition period. However, asphaltene precipitation may become a problem with increasing the molecular weight of injected alcohol.

Analysis of Field Data Using Microsoft Excel and MATLAB Software to Evaluate Reservoir and Well Damage

Reservoir formation damage is a drop in a well's productivity caused by a decrease in reservoir rock permeability. To tackle this issue and maximize well production, obtained pressure build-up time data at a steady production rate from a vertical producing oil WELL 20A, was analysed to establish the wellbore and reservoir characteristics. A numerical well test simulator (Matlab) is used to simulate damage in the area close to the wellbore, a Microsoft Excel sheet and an analytical approach to calculate the impact of wellbore and reservoir factors such as skin, wellbore storage, and average reservoir permeability. In order to determine whether the numerical well test simulator was successful at performing pressure transient analysis on observed data, the findings from the analytical solutions using Microsoft Excel Sheet and numerical well test simulator Matlab were compared. Comparable outcomes for the permeability and skin values were obtained from the build-up test data analysis generated; hence, the negative skin values for wells 20A acquired after the analysis suggest that the formation is not damaged. This indicate that well 20A is not a candidate for workover operations.

Multi-Sized Granular Suspension Transport Modeling for the Control of Lost Circulation and Formation Damage in Fractured Oil and Gas Reservoirs

Transport and retention of multi-sized suspended granules are common phenomena in fracture media of oil, gas and geothermal reservoirs. It can lead to severe permeability damage and productivity decline, which has a significant impact on the efficient development of underground resources. However, the granule transport and retention behaviors remain not well understood and quantified. The novel stochastic model is proposed for the multi-sized suspended granule transport in naturally fractured reservoirs accounting for granule retention and fracture clogging kinetics. A percolation fracture network is proposed considering fracture connectivity evolution during suspended granule transport. Granule retention and fracture clogging dynamics equations are proposed to account for incomplete fracture clogging by retained granules. The microscale stochastic model is allowed for upscaling to predict the multi-sized granule transport behavior in naturally fractured reservoirs. The model solution exhibits preferential plugging of fractures with sizes equal to or below the granule size. Multi-sized suspended granule shows great advantages over mono-sized suspended granule in the control of permeability damage induced by granule retention and fracture clogging. The retained granule concentration and permeability damage rate decrease with fracture network connectivity improvement. The experimental investigation on size-exclusion suspended granule flow has been performed. The model-based prediction of the retained granule concentration and permeability variation history shows good agreement with the experimental data, which verifies the developed model.

Experimental Investigation on the Penetrability Mechanism of Gel Slug During Well Completion Processes.

Reservoir formation damage is an essential problem which troubled oil and gas well production, a smart packer is a promising technology to maintain sustainable development for the oil and gas fields. Currently, the "gel valve" technology has been proved to be feasible with gel slug to seal casing and descend the completion pipe string, while the systemic performance of ideal gel is still not clear. In the underbalanced completion stage with the gel valve, the downward completion string needs to penetrate the gel slug to form an oil and gas passage in the wellbore. The penetration of rod string to gel is a dynamic process. The gel-casing structure often shows a time-dependent mechanical response, which is different from the static response. In the process of penetration, the interaction force between the rod and gel is not only related to the properties of the interface between gel and string but also affected by the moving speed, rod diameter, and thickness of the gel. The dynamic penetration experiment was carried out to determine the penetrating force varied with depth. The research showed that the force curve was mainly composed of three parts, the rising curve of elastic deformation, decline curve for the surface worn out, and another curve of the rod wear into. By changing the rod diameter, gel thickness, and penetration speed, the change rules of forces in each stage were further analyzed, which would provide a scientific basis for a well completion design with a gel valve.

Technology Focus: Formation Damage (March 2023)

Identification, prevention, and remediation of formation damage during the life cycle of oil and gas wells are key for our industry to allow wells to perform to their full potential. Increased awareness of potential damage mechanisms along with improvements in laboratory testing equipment and methodologies have proven to be instrumental in efficient prevention and remediation of formation damage in production and injection wells in conventional reservoirs. While the ongoing technical studies and technology developments in the area of formation damage are heavily focused on key damage-mechanism scenarios during drilling and production, such as drilling-fluid-induced damage, scaling, clay swelling, fines migration, and incompatibility of fluid/fluid and fluid/rock in conventional sandstone and carbonate reservoirs, there are new research activities and increased applications of learnings in low-permeability unconventional reservoirs and carbon capture and storage (CCS). In low-permeability unconventional reservoirs, hydraulic fracturing has proven instrumental for economic and successful development. Injection of a large volume of fracturing fluid water is necessary to place the required quantity of proppant to generate and maintain fracture conductivity, thereby increasing the risk of fracturing-fluid-induced formation damage. New laboratory studies and field trials to select suitable preventive additives in fracturing fluid and optimize flowback processes are being deployed to prevent formation damage not only from gelling materials, friction-reducer chemicals, and water blockage but also from scaling and paraffin during production. Identification and prevention of formation-damage mechanisms affecting injectivity during CO2 injection in subsurface for CCS and CO2 enhanced oil recovery are critical. Enjoy the papers chosen this year, some of which highlight my comments and the innovation and successes achieved by our industry in identification, prevention, and remediation of formation damage in conventional reservoirs, which is expected to bring success in area of unconventional-reservoir development and carbon reduction. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 22543 Formation Damage in the Hollín Sandstone: Diagnosis, Evaluation, and Stimulation Practices From Laboratory to Field Implementation, Sacha Field, Ecuador by Alvaro Izurieta, Halliburton, et al. SPE 208852 Understanding Fluid Exchange as Screens Are Run in Hole—Mitigation of Formation and Completion Damage Risks by Michael Byrne, Axis, et al. SPE 210763 Near-Wellbore Damage Associated With Formation Dry-Out and Fines Migration During CO2 Injection by Liam Alchin, The University of Adelaide, et al.

Compatibility Coreflood Studies Explore Formation Damage in Tight Reservoirs

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207764, “Case Study of Identifying and Minimizing Formation Damage in Tight Reservoirs Caused by Drilling Fluids in Abu Dhabi Onshore Operation Using Compatibility Coreflood Studies,” by Raymond Saragi, Mohammad Husien, and Dalia S. Abdullah, ADNOC, et al. The paper has not been peer reviewed. _ The authors examine formation-damage mechanisms caused by drilling fluids in tight reservoirs in several onshore Abu Dhabi oil fields. Three phases of compatibility corefloods were performed to identify the potential of improving hydrocarbon recovery and examine reformulated or alternate drilling muds and treatment fluids. The compatibility corefloods on tight reservoir cores, along with high-resolution quantifications and visualizations, identified damaging mechanisms and helped identify potential to improve hydrocarbon recovery and treatment-fluid options. Introduction The operator examined drilling-mud performance for UAE fields including Bab, Rumaitha, Qusahwira, Sahil, and Mender. Results appeared to be good in high-permeability zones but not in lower-permeability zones. A multiphase compatibility study consisting of a series of coreflood simulations analyzed both producer and injector wells, but the complete paper focuses on the producer wells. The use of nano-computed tomography (CT) scans and cryogenic scanning electron microscope (SEM) with energy dispersive spectroscopy (EDS) as interpretative tools provided insights into the coreflood results (55 of which are presented in the complete paper). The reservoirs consist of Lower Cretaceous carbonate sediments. This study examined lower-permeability zones; the results shown in the complete paper are only from the tight samples below 15 md. The samples used in the study are detailed in Table 1 of the complete paper and represented the following reservoirs: - Bab (wells coded BB-1, BB-2, BB-3, BB-4, BB-5, BB-6, and BB-7; 0.1–15-md gas permeability) - Mender (well coded MN-1; 3–12-md gas permeability) - Qusahwira (wells coded QW-1 and QW-2; 0.5–1-md gas permeability) - Rumaitha (well coded RA-1; 2–15-md gas permeability) - Sahil (well coded SA-1; 2–4-md gas permeability) Methodology Coreflood simulations were performed using specialized equipment capable of executing the study at reservoir conditions while eliminating artifacts such as corrosion. Accurate replication of reservoir conditions is important, especially where potential scaling exists. Phase 1 examined permeability alterations and damaging mechanisms after application of the currently used drilling mud. The methodology is detailed in the complete paper, but the authors emphasize the use of interpretive tools in this process. Phase 2 examined a series of reformulated and alternate drilling muds. Following the results of Phase 1, the current field mud was reformulated and examined as Reformulated Mud Formulation 1 alongside three alternate drilling muds from separate vendors. Phase 3 built on Phases 1 and 2 by examining the incorporation of a displacement or treatment fluid as part of the operational sequence. The methodology for Phase 3 was similar to that used in the previous phases, with the addition of treatment-fluid application before drawdown.

Effect of Seepage Velocity on Pore Clogging Growth Behavior and Its Effect on Permeability Reduction During Fines Migration in Porous Media

AbstractFines migration driven by fluid flows often causes pore clogging in porous media and thus reduces the permeability of the porous media. The clogging can pose serious problems in various practices, such as formation damage in hydrocarbon reservoirs, degradation of fluid withdrawal or injection efficiency, particle‐induced fouling in filtration membranes, or even a risk of sediment failure with geostructures. However, the effect of seepage flow velocity on the spatial growth pattern of fines‐induced pore clogging remains poorly identified. This study explores the pore clogging growth behaviors caused by flow‐driven fines migration and accumulation in porous media and the associated permeability reductions through a series of column experiments and concurrent X‐ray computed tomography imaging. Particularly, the X‐ray image analysis captures the spatial distributions of fines, and thus the homogeneous or heterogeneous (localized) clogging growth pattern under various seepage velocities. Our results reveal that an increase in the seepage flow velocity increases the likelihood of localized clogging growth, attributable to the direct interception of fines by the sand grains. The localized clogging growth causes a faster reduction in permeability than the homogeneous clogging growth. The presented study provides well‐controlled experiment data on fines distribution and associated permeability change, which gives insights into fines‐induced clogging behavior in porous media.

An integrated modeling approach to predict critical flow rate for fines migration initiation in sandstone reservoirs and water-bearing formations

Fines migration causes formation damage in sandstone reservoirs and water-bearing subsurface formations. Several factors affect fines migration such as composition and salinity of permeating brine, flow rate, and system pH. Electrostatic forces of van der Waals attraction and electric double layer repulsion, gravitational force and hydrodynamic force all contribute to fines detachment and migration under certain conditions. The current research presents a new integrated model of electrostatic, gravitational, and hydrodynamic forces to estimate the critical injection rate of NaCl brine for fines migration initiation in subsurface formations.The DLVO modeling approach was modified by considering electrostatic, hydrodynamic, and gravitational forces. Parameters such as injection brine salinity, average fine particle size, and zeta potential of sand-brine systems were used, and effective forces were quantified. A microscopic force and torque balance approach was applied to model hydrodynamic forces to modify the DLVO model. The developed models were validated with experimental results.The profiles of injection velocity versus fine particle radius were generated and the models predicted critical flow rates of 0.9, 2.6, and 3.8 cc/min for 0.15 M, 0.2 M, and 0.25 M NaCl, respectively. For model validation, the coreflood experiments were performed on Berea sandstone core samples under given salinities and critical flow rates were determined. Comparable experimental results were obtained with critical flow rates of 1, 3, and 4 cc/min for 0.15 M, 0.2 M, and 0.25 M NaCl, respectively. In addition, sensitivity analysis assesses the impact of different forces on the fines migration phenomenon.Formation damage caused by fines migration is a well-documented problem in sandstone reservoirs and water-bearing formations. Regulating the injection/ permeating fluid rate and salinity can avoid fines migration and associated permeability impairment. Our study presents a novel approach incorporating electrostatic, gravitational, and hydrodynamic forces to accurately predict fines mobilization in fine-containing subsurface formations.

Subsection and superposition method for reservoir formation damage evaluation of complex-structure wells

Kinds of complex-structure wells can effectively improve production, which are widely used. However, in the process of drilling and completion, complex-structure wells with long drilling cycle and large exposed area of reservoir can lead to the fact that reservoir near wellbore is more vulnerable to the working fluid invasion, resulting in more serious formation damage. In order to quantitatively describe the reservoir formation damage in the construction of complex-structure well, taking the inclined well section as the research object, the coordinate transformation method and conformal transformation method are given according to the flow characteristics of reservoir near wellbore in anisotropic reservoir. Then the local skin factor in orthogonal plane of wellbore is deduced. Considering the uneven distribution of local skin factor along the wellbore, the oscillation decreasing model and empirical equation model of damage zone radius distribution along the wellbore direction are established and then the total skin factor model of the whole well is superimposed to realize the reservoir damage evaluation of complex-structure wells. Combining the skin factor model with the production model, the production of complex-structure wells can be predicted more accurately. The two field application cases show that the accuracy of the model can be more than 90%, which can also fully reflect the invasion characteristics of drilling and completion fluid in any well section of complex-structure wells in anisotropic reservoir, so as to further provide guidance for the scientific establishment of reservoir production system.

The Role of Particle Size Distribution for Fluid Loss Materials on Formation of Filter-Cakes and Avoiding Formation Damage

Abstract Numerous studies have shown that careful particle size selection is the main parameter for reducing fluid loss when drilling permeable or fractured formations. The methods are generally built around either the D50 or D90 values of the particles in the fluid as a relative size to the pore openings of the formation to minimize fluid loss. A series of studies were conducted with the aim of assessing if analysis of fluid loss could be used to separate the formation of internal and external filter-cakes, thereby enabling a more accurate estimate of the permeabilities of the internal and external filter-cakes. It was concluded that conventional particle size methods were found to be adequate for designing a fluid for wellbore stabilization purposes. This led to higher solids invasion and a more impermeable internal filter-cake. However, for optimization of reservoir drilling fluids, a different particle size selection method was found to be more useful to prevent reservoir formation damage. This method involves selecting particles that are resistant towards shear-degradation and with a D90 particle size ⪞3/2 the pore size of the formation. By analyzing fluid loss regression data and correlating these with indicators of formation damage, such as disc mass and permeability change, it was found that a ratio defined as the relative plugging factor could provide insight into the extent of solids invasion into the formation and potential formation damage.

Temperature Transient Analysis of Naturally Fractured Geothermal Reservoirs

Summary A potential approach to develop geothermal energy is by producing low-to-medium temperature fluids from naturally fractured geothermal reservoirs (NFGRs). Pressure transient analysis (PTA) is the most common approach to characterize such reservoirs for improving development efficiency. However, pressure inversion leads to nonuniqueness and cannot be used to estimate thermal properties. Moreover, reliable methods to evaluate the development potential of fractured geothermal reservoirs are lacking. To address the gap, this work aims to study the temperature behavior and explore a suitable analysis method for characterizing geothermal reservoirs and evaluating development potential. We developed numerical and analytical models to analyze the temperature behavior in NFGRs. The developed models account for the Joule-Thomson [J-T effect (μJT)], adiabatic heat expansion/compression effect (ζ), reservoir formation damage, heat conduction, and convection effects. The developed numerical solution is verified and found to agree with the proposed analytical solutions. The results show that temperature transient analysis (TTA) with constant or temperature-dependent μJT and ζ assumption leads to a minor difference when reservoir temperature changes significantly. Moreover, three heat radial flow regimes (HRFR) and a thermal interporosity regime with a V-shape characteristic have been identified. The results also show that temperature data provide information not accessible by PTA. The results reveal that temperature derivative curves signify a “hump” when formation around a wellbore is damaged, and the temperature data can be used to characterize the skin-zone radius and permeability. It is demonstrated that the properties such as J-T coefficient, effective adiabatic heat expansion coefficient, and fracture intrinsic porosity can be estimated using TTA. The results indicate that fracture thermal storativity (ωT) and matrix thermal interporosity coefficient (αT) can be estimated from the thermal interporosity regime exhibited on the temperature derivative curve. The results also suggest that commercial geothermal energy harness is more difficult when the ωT is high or the αT is very small. Finally, we introduced an integrated workflow of combining PTA and TTA to characterize NFGRs. Simulated test examples are interpreted to demonstrate the applicability of the developed workflow. This work aids in better understanding the potentials of temperature data on geothermal reservoir characterization.

Developing novel bio-nano catalyst well clean up fluid to remove formation damage induced by polymeric water-based drilling fluids

Drilling and completion fluids may cause significant formation damage in oil and gas reservoirs, directly affecting productivity. For many years, operators have applied different stimulation practices such as acidizing, oxidizers, chelating agents, and enzyme treatment to remove formation damage associated with drilling fluids filter cake. An enzyme-based biological treatment was combined with other chemicals or additives as a selective well clean-up practice to improve removing polymer content in the filter cake. However, the secondary formation damage such as deep cleaning of the invaded zone and wettability alteration remained the main concern. This paper presents the development of an innovative clean-up fluid formulation by immobilizing an enzyme and a selective nanoparticle as Bio-Nano Well Clean-Up Fluid (BNWC) in potassium chloride brine to enhance WBM filter cake removal. Several bulk experiments, including; precipitation, iodine test, and viscosity measurement, demonstrate the enzyme's optimization, the nanoparticle concentration, and base fluid brine. BNWC in potassium chloride brine showed the highest HPHT filtration rate at 200 °F and differential pressure of 100 psi and increased the filtration rate by more than 90 percent compared to the conventional enzyme in the same brine. Contact angle measurements confirmed wettability alteration of the carbonate rock to water-wet, and IFT measurements showed higher oil mobility potential. Finally, core flooding tests at reservoir conditions showed a 300 percent enhancement in injection rate and a 50% improvement in core permeability after damage. The immobilization of the enzyme with the nanoparticle has been developed successfully for other applications in bioremediation, farming, and other industries, but the novelty of this research demonstrates the application of nanobiocatalysts in drilling fluids for the first time. This innovative clean-up fluid enhances the enzymatic activity and removes primary and secondary formation damage associated with drilling fluid filter cake.

Quantitative Investigation of Water Sensitivity and Water Locking Damages on a Low-Permeability Reservoir Using the Core Flooding Experiment and NMR Test.

Production of oil and gas energy is often greatly hindered by reservoir formation damage, particularly the occurrences of water sensitivity and water locking damages on a low-permeability reservoir. For the purpose of this paper, a formation damage assessment methodology combining core flooding experiment and NMR (nuclear magnetic resonance) T2 relaxation tests is performed and applied to quantitatively determine water sensitivity/water locking damage on sandstone oil formation. XRD tests are used to analyze the mineral composition of cores. Core flooding experiments are designed to simulate the two damages and determine the permeability reduction. NMR tests are introduced to compare water saturation before and after flooding through rock cores, calculate the porosity damage and changes of the pore size, and analyze the mechanism of water sensitivity and water locking damages. Also, SEM experiments are used to determine the pore morphology before and after damage. Low-permeability sandstone rock cores cored from the Jilantai reservoir are assessed through this whole set of experiments. The results demonstrate that the permeability and porosity of core samples strongly decrease with the occurrence of water sensitivity/water locking damage, reflecting that the Jilantai reservoir has strong water sensitivity and is prone to be damaged by water locking. Compared with the previous formation damage assessment ideas, much attention is given to the microchanges of cores after damage, and using fluorinated oil instead of kerosene can help observe the distribution of water in rock core samples after each flooding by the NMR T2 spectra.

Reservoir Formation Damage; Reasons and Mitigation: A Case Study of the Cambrian–Ordovician Nubian ‘C’ Sandstone Gas and Oil Reservoir from the Gulf of Suez Rift Basin

Reservoir formation damage is a major problem that the oil and gas industry has to mitigate in order to maintain the oil and gas supply. A case study is presented that identifies the impacts of formation damage and their causes in the Nubian ‘C’ hydrocarbon reservoir within Sidki field located in the Southern Gulf of Suez, Egypt. In addition, a formation damage mitigation program was designed and implemented involving an effective stimulation treatment for each well experiencing reservoir damage. The data available for this study include core analysis to provide rock mineralogy and lithology; analysis of production fluid data; water chemistry; drilling fluid composition; perforations and well completion details; workover operations; and stimulation history. The diagnosis of formation damage based on the integrated assessment of the available data is associated with several benefits, (1) The integration of the data available helps provide a robust analysis of formation damage causes and in establishing suitable remediation actions, (2) Workover fluid is confirmed as the primary cause of reservoir damage in the studied well, (3) Several reservoir damage mechanisms were identified including water blockage, solids and filtrate invasion, fluid/rock interaction (deflocculation of kaolinite clay), salinity shock and/or high-sulfate content of the invaded fluid, (4) Irrespective of the potential causes of formation damage, the primary objective of a gas production company is to mitigate its effects and the integrated dataset helps to design appropriate and effective stimulation treatments to overcome formation damage, and (5) In gas reservoirs, especially low permeability ones, extra precautions are necessary to avoid potential reservoir damage due to workover fluid invasion.

Numerical simulation of formation damage by drilling fluid in low permeability sandstone reservoirs

Understanding the formation damage surrounding the well during the drilling operation is the key to predict damage degree and protect the formation in oil/gas reserviors. Based on the core drainage results, we obtained an empirical relationship between the invasion volume of drilling fluid and permeability reduction of formation. Furthermore, the equation is incorporated into a commercial reservior numerical simulation simulator to characterize the behaviors of drilling fluid invasion process. The results show that, although the invasion depth in low permeability reservoirs is short with the range of 1.7–2.5 m, the effect on recovery factor is significant due to the narrow seepage area in the near fracture region. When considering the formation damage, the pressure in the near-fracture damage region drops sharply, leading to a three-stage shape in pressure distribution curve. In addition, we found that high viscosity and low density oil-based slurry and shorter soaking period are conducive to decrease the formation damage during drilling operation. This work reveals the fundamental mechanisms of formation damage in low permeability reservoirs, which is a theoretical basis in formulation drilling fluids and optimization operation parameters.

Study of pressure behaviour of a well near two intersecting faults

A pressure builds up test was performed in a dry gas exploration well. According to geological data indicated that there are two intersecting faults near the well. The analysis result provided not only information of the reservoir characteristics such as average reservoir pressure, permeability, and formation damage, but also confirmation of the presence of those two intersecting faults. In this study, a reservoir simulator was used to model pressure build up test of a well located near two intersecting faults. The effect of several parameters namely the distance between well to the faults, flow rate, and reservoir pressure, on bottom hole pressure behaviour was observed. The simulation results showed that the effect of variation of the distance between well and faults as well as that of reservoir pressure on estimation of permeability and skin factor is not significant. While, the variation of flow rate may result in a significant deviation. If a constant flow rate cannot be maintained during flowing period of the pressure build up test.

Kaolinite fines colloidal-suspension transport in high temperature porous subsurface aqueous environment: Implications to the geothermal sandstone and hot sedimentary aquifer reservoirs permeability

Phyllosilicates, specifically, the kaolinite clay mineral (Al2Si2O5(OH)4), which is a layered silicate mineral with one silica tetrahedral sheet connected with oxygen atoms to one alumina octahedral octahedral sheet is ubiquitous and abundant in sedimentary basins, especially sandstone formations. This particular type of clay mineral fine particles can easily and rapidly cause reservoir formation damage in high temperature aquifers, geothermal, and petroleum reservoirs by detaching from the porous rock surface and migrate, and plug the pore-throats of the rock matrix. Several factors such as, reservoir temperature, pressure, geochemical alteration, permeating fluid, reactive flow, and multi-phase flow are attributed to the permeability decline of the porous rocks and subsequent fluid flow reduction, and consequently, leading to well productivity loss. Therefore, this paper presents laboratory modeling of fines transport in the hot porous sedimentary aquifer. This type of aquifer is located in sedimentary basins with the elevated heat flow and having a characteristic of a shallow depth and a high volume, which indicates a high natural porosity and permeability. In this work, we have conducted three sets of coreflood experiments in the temperature ranges of 125 °C 150 °C, and 175 °C. Kaolinite suspension water has been injected into the porous sandstone core at these temperatures to investigate the feasibility of a permeability and injectivity decline. The major experimental results revealed that there is an increase in water saturation and heat transfer rates. The concentration of fines surges with increasing PVI and permeability declines with increased time. Pressure soars with increasing Pore Volume Injection (PVI), but it stabilized after some time. Actually, PVI is a ratio of cumulative water injection to each pore chamber volume of the rock core. Importantly, the water discharge rate decreases with increasing suspension injection and on the other side, with fresh water injection, the rate of water discharge rises steadily. Furthermore, the experimental and mathematical models were tested against statistical model, multiple linear regression for validation. The modelling results showed good agreement and, therefore, this paper has explicated the significance of fines transport in aquifers under hot sedimentary basins.

Multiscale Investigation of a Less-Damaging Friction Reducer to Mitigate Formation Damage in Unconventional Shale Reservoirs

Multiscale Investigation of a Less-Damaging Friction Reducer to Mitigate Formation Damage in Unconventional Shale Reservoirs

Experimental, algorithmic, and theoretical analyses for selecting an optimal laboratory method to evaluate working fluid damage in coal bed methane reservoirs

The existing laboratory methods have limitations that make it very difficult to select the most suitable method for obtaining precise permeability measurements for evaluating reservoir formation damage. To date, there has been no research critically addressing this issue. In this study, the permeabilities of core or cuttings samples taken from No.15 Reservoir in the Qinshui Basin before and after damage caused by drilling and fracturing fluids were randomly measured using six general laboratory methods. Their average permeability values, as well as the extent of absolute and relative formation damage, were calculated and analyzed using a simple ranking method, statistical screening algorithm, and theoretical method. The results show that, first, there is a regular distribution of absolute reservoir damage measured by the laboratory methods; and second, the application priority of permeability measurement methods for formation damage evaluation in coal bed methane reservoirs is as follows: cuttings pulse decay method > constant flow rate method > nuclear magnetic resonance method > plunger pulse decay method = pressure oscillation method = constant pressure method. The cuttings pulse decay method is therefore recommended for measuring core matrix damage, while the constant flow rate method is suggested for measuring overall damage to core samples.

ASSESSMENT OF MAGNESIUM OXIDE (MGO) AND SILICA DIOXIDE (SIO2) NANO-FLUIDS ADDITION WITH SURFACTANTS AS NEW TECHNIQUE TO CONTROL FINES MIGRATION

Formation damage in oil reservoirs because of fines migration is among the main contributors to productivity decline. Conventionally, chemical methods such as complex organic polymers are used to prevent fines migration by stabilizing or maintain the fines particles in aggregated form. However, most of the chemical fines stabilizer is not robust, which functionalize based on the composition of exchangeable cations in clay minerals, temporary stabilization and are not environmentally friendly. In this research work, qualitative methods were developed to investigate the potential of Magnesium Oxide (MgO) and Silica Dioxide (SiO2) Nano-Fluids addition with surfactants (Triton X-100 and Tween 80) as a new technique to control fines migration. Silicon Dioxide nanoparticles used in this experiment are in the form of colloidal silica with spherically sized at 10-15 nm then stabilized electrostatically to allow the particles to stay suspended in the solution. To measure the Nano-Fluids and fines solution stability, the minerals (kaolinite, bentonite and illite-smectite) crushed and suspended in 100 mL distilled water with 0.20%, 0.50%, 1.50% and 3% concentration,respectively. The suspended fines solutions left for 24 hours. Solution stability measured using the Zetasizer Nano ZSP by recording their turbidity (NTU) and zeta potential (mV). The results from the assessment shown that bentonite and kaolinite fines are more susceptible to migration in sandstone reservoirs due to their high colloidal stability from their zeta potential measurements and their morphologies. It can also be concluded that Silicon Dioxide (SiO2) is more stable when these nanoparticles are suspended in de-ionized water only, which gives zeta potential values of -26.10 mV. The addition of surfactants (Triton X-100 and Tween 80) has also shown significant results on protected fines migration. Triton X-100 and Tween 80 increased Silicon Dioxide (SiO2) Nano-fluid zeta potential value at -30.6 mV, which is beneficial for the Nano-Fluid to travel deeper into the formation to treat problematic areas of fines migration.Keywords: MgO and SiO2 nano-fluid, zeta potential, fines migration, surfactant, nanoparticles