Reduce Formation Damage Research Articles

Synergistic Effects between Supercritical CO2 and Diluted Microemulsion on Enhanced Oil Recovery in Shale Oil Reservoirs

Summary In the context of developing unconventional liquid-rich reservoirs, the application of supercritical carbon dioxide (sc-CO2) has shown many advantages, including enhanced oil recovery (EOR), reducing formation damage, reducing water usage, and promoting the formation of complex fracture networks. However, sc-CO2 faces certain limitations in shale oil reservoirs that hinder its widespread application, such as ultralow viscosity, asphaltene deposition, and high miscible pressure. The addition of chemical agents is expected to overcome some limitations of sc-CO2 and further improve the CO2-EOR performance. Diluted microemulsion (DME) shows great potential as a chemical additive in water-based fracturing fluids to improve oil recovery by wettability alteration during the shut-in period after hydraulic fracturing. It is essential to explore the synergistic mechanism of DME and sc-CO2 through laboratory experiments to understand the microscopic mechanism of oil mobilization in shale reservoirs and to guide field applications. In this study, three soaking sequences were designed and compared to explore the EOR mechanisms combining sc-CO2 with DME using crude oil and core samples from the Lucaogou shale formation. To distinguish the DME at different stages, the DME injection in the subsequent stage is referred to as post-DME (pDME). The soaking sequences consist of only sc-CO2 soaking, water–sc-CO2–pDME (W-C-D) soaking, and DME–sc-CO2–pDME (D-C-D) soaking. They correspond, respectively, to the CO2 fracturing process and the process of CO2-EOR technology after hydraulic fracturing with different water-based fracturing fluids. Low-field nuclear magnetic resonance (NMR) technology was used to quantify the oil distribution among different pores and to monitor changes in the fluid state during each soaking stage. Additionally, the component changes of the produced oil were characterized using gas chromatography (GC). The T2 spectra results indicate that sc-CO2 soaking yields the highest oil recovery in the first soaking stage compared with water soaking and DME soaking. DME soaking effectively mobilizes more oil in small pores than water soaking. Subsequent sc-CO2 soaking and pDME soaking exhibit better EOR performance in the W-C-D soaking sequence than in the D-C-D soaking sequence, primarily mobilizing the remaining oil in larger pores. The sequence of total oil recovery is D-C-D soaking > only sc-CO2 soaking > W-C-D soaking. While the total oil recovery from large pores is similar across different soaking sequences, the D-C-D sequence achieves the highest oil recovery in small pores. The GC results suggest that DME can enhance the recovery of heavy components (C17+) by reducing interfacial tension (IFT) and altering wettability, thereby providing a conducive environment for heavy component mobilization in the subsequent soaking period. DME enables balanced mobilization of both heavy and light components, while sc-CO2 enhances oil mobilization from the unswept area by the aqueous phase. Therefore, combining sc-CO2 and DME can result in a higher ultimate oil recovery factor in shale oil reservoirs. The findings of this study provide an in-depth understanding of the oil mobilization mechanism during the soaking period and inform the design of soaking sequences for field applications in shale oil reservoirs.

Foam Properties Evaluation under Harsh Conditions: Implications for Enhanced Eco-Friendly Underbalanced Drilling Practices

Summary Foam drilling offers advantages such as reduced formation damage and faster drilling in underbalanced drilling (UBD) operations. The efficacy of foam drilling is influenced by factors including pressure, temperature, salt content, foam quality, and pH levels. However, a gap exists in the evaluation of foam properties under rigorous conditions, particularly those involving high pH and mixed salt environments common in drilling scenarios, highlighting the need for further research. In this study, a high-pressure, high-temperature (HPHT) foam analyzer and rheometer were employed to examine the stability and rheological behavior of ammonium alchohol ether sulfate (AAES) foam under simulated alkaline drilling conditions. The foaming solution, designed to replicate such conditions, consisted of synthetic seawater (SW) with a salt mixture totaling approximately 67.70 g/L and a 0.5 wt.% foaming agent adjusted to a pH of 9.5. This approach differs from the individual salt studies prevalent in existing literature and provides a unique perspective on foam stability and behavior. Driven by environmental sustainability considerations, the effects of eco-friendly surfactant AAES and various drilling fluid additives: polyanionic cellulose (PAC), carboxymethyl cellulose sodium (CMC), and xanthan gum (XG), were investigated for foam formulation. The apparent viscosity of the AAES foam was evaluated at different pressures and temperatures across varying shear rates. A consistent decrease in foam viscosity with increasing shear rates was observed, irrespective of pressure and temperature. An increase in foam viscosity was also noted with higher pressures (from 14.7 psi to 3,000 psi) at low shear rates, with values rising from 8.04 cp to 14.74 cp, and from 3.71 cp to 5.79 cp at high shear rates of 1,000 s⁻¹. Increasing foam quality from 65% to 85% resulted in significant improvements in viscosity, approximately 37% at low shear rates and about 79% at high shear rates. The introduction of additives to AAES foam at 1,000 psi and 90°C led to a substantial increase in viscosity, with PAC showing the most significant enhancement: 33.28 cp at low shear rates and 18.15 cp at high shear rates. Conversely, the viscosity of both base AAES foam and additive-enhanced foams decreased with rising temperatures, although PAC exhibited the greatest resistance to viscosity variations due to temperature changes. The addition of PAC also resulted in a notable increase in foam yield stress, potentially leading to more efficient cuttings transport and hole cleaning. Furthermore, foam stability was significantly improved by the additives, with XG and CMC doubling stability to 48 minutes, and PAC resulting in a threefold increase in half-life to 65 minutes. This study presents AAES and the tested additives as viable components for eco-friendly foam formulations, promoting enhanced properties suitable for UBD applications.

A Novel Fracturing Fluid Based on Functionally Modified Nano-Silica-Enhanced Hydroxypropyl Guar Gel.

Considering the damage caused by conventional fracturing fluid in low-permeability reservoirs, a novel fracturing fluid (FNG) combining hydroxypropyl guar (HPG) and functionally modified nano-silica (FMNS) was prepared. The properties of heat/shear resistance, rheological property, proppant transportation, and formation damage were evaluated with systematic experiments. The results showed that the viscosities of FNG before and after the heat/resistance were 1323 mPa·s and 463 mPa·s, respectively, while that of conventional HPG gel was 350 mPa·s. FNG is a pseudoplastic strong gel with a yield stress of 12.9 Pa, a flow behavior index of 0.54, an elastic modulus of 16.2 Pa, and a viscous modulus of 6.2 Pa. As the proportions of proppant mass in further sections transported with FNG were higher than those transported with HPG gel, FNG could transport the proppant better than HPG gel at high temperatures. Because of the amphiphilic characteristics of FMNS, the surface/interface properties were improved by the FNG filtrate, resulting in a lower oil permeability loss rate of 10 percentage points in the matrix than with the filtrated HPG gel. Due to the considerable residual gel in broken HPG gel, the retained conductivity damaged with broken FNG was 9.5 percentage points higher than that damaged with broken HPG gel. FNG shows good potential for reducing formation damage during fracturing in low-permeability reservoirs in China.

Optimizing Recovery of Fracturing Fluid in Unconventional and Tight Gas Reservoirs Through Innovative Environmentally Friendly Flowback Additives

Hydraulic fracturing, a method used to stimulate oil and gas from shale and tight formations, faces challenges like fluid blockage and fast declining oil or gas production rates due to the significant impact of capillary forces on water retention. To address this, surfactants and microemulsions are commonly employed as flowback additives to reduce surface and interfacial tension, enhancing water recovery during hydraulic fracturing. The effectiveness of flowback additives is highly impacted by harsh subsurface conditions, such as high salinity and high temperature. This study aims to assess the performance and effectiveness of methylimidazolium chloride-based ionic liquids as flowback additives at high salinities and temperatures.Different experimental analysis were conducted to screen different concentrations of methylimidazolium chloride-based ionic liquids (X1, X2, and X3). Surface tension measurements were conducted to estimate the critical micelles concentrations. A spinning drop tensiometer (SDT) was utilized to measure interfacial tension, in addition, contact angle measurements were used to evaluate the impact of the flowback additive on the wettability and the displacing behavior. Seawater was used as the base fracturing fluid with a salinity of 57,000 ppm and temperatures up to 90°c for all experiments. Coreflood experiments were conducted using tight formations to evaluate the regained hydrocarbon permeability and the fracturing fluid recovery in the presence of flowback additives.Various formulations, with surface tension values ranging from 30 to 45 mN/m and CMC values between 0.5 and 1 gallon per thousand units (gpt), were examined. The lowest interfacial tension value, notably 3 mN/m, was achieved with the X3 formulation. Ionic liquids demonstrated favorable surface tension reduction, where longer carbon chains led to lower values. Introducing diverse ions, especially divalent ions, enhanced the performance of ionic liquids. Interfacial tension measurements indicated a significant reduction with the addition of X3 to both 5 wt% KCl and the fracturing base fluid. Contact angle measurements revealed a shift towards greater water-wettability after treating the rock with flowback additives. Moreover, the use of ionic liquids improved permeability by 25%, enhancing fluid recovery to around 56%.According to our results, methylimidazolium chloride-based ionic liquids can be used as environmentally friendly flowback additives, especially in harsh conditions of high temperature and high salinity where the conventional additives are not suitable. This will contribute to the development of more sustainable and environmentally conscious practices in hydraulic fracturing operations. Ultimately, the utilization of these additives can help mitigate water blockage, reduce formation damage, and enhance shale gas production.

Impact of Pressure and Temperature on Foam Behavior for Enhanced Underbalanced Drilling Operations.

Foam, a versatile underbalanced drilling fluid, shows potential for improving the drilling efficiency and reducing formation damage. However, the existing literature lacks insight into foam behavior under high-pH drilling conditions. This study introduces a novel approach using synthesized seawater, replacing the conventional use of freshwater on-site for the foaming system's liquid base. This approach is in line with sustainability objectives and offers novel perspectives on foam stability under high-pH conditions. Experiments, conducted with a high-pressure, high-temperature (HPHT) foam analyzer, investigate how pressure and temperature affect foam properties. The biodegradable foaming agent ammonium alcohol ether sulfate (AAES) is employed. Results demonstrate that the pressure significantly impacts foam stability. Increasing pressure enhances stability, reducing decay rates and promoting uniform bubble sizes, especially at lower temperatures. This highlights foam's capacity to withstand high-pressure conditions. Conversely, the temperature plays a substantial role in foam decay, particularly at elevated temperatures (75 and 90 °C). Decreased liquid viscosity accelerates the liquid drainage and foam decay. While pressure mainly influences the AAES foam stability at temperatures up to 50 °C, temperature becomes the dominant factor at higher temperatures. Temperature's impact on foamability is minimal under constant pressure, maintaining consistent gas volume for maximum foam height. However, foam stability is sensitive to temperature variations, with increasing temperature leading to a more significant bubble size increase gradient. These findings stress the importance of considering temperature effects in foam drilling, particularly in deep and high-temperature environments. AAES foam exhibits stability at lower temperatures, making it suitable for surface and intermediate drilling. Understanding temperature-induced changes in foam structure and bubble size is essential for optimizing performance in high-temperature and deep drilling scenarios.

Exploring Underbalance Drilling: A Comprehensive Review

Underbalance Drilling (UBD) is an advanced drilling technique employed in oil and gas industry to improve well productivity and reduce formation damage. In conventional drilling, overbalance conditions are maintained in order to prevent the influx of formation fluids. In contrast, UBD involves maintaining a hydrostatic pressure lower than the formation pressure during drilling operations. UBD offers several advantages, such as increasing drilling rates, reducing formation damage, improving wellbore stability. By preventing the flow of drilling fluids in to the formation, UBD reduces the risk of formation plugging and improves the recovery of hydrocarbons. This technique is particularly beneficial for depleted reservoirs or formations prone to lost circulation problems. Despite its advantages, proper planning and execution are essential for UBD to manage the associated risks, such as wellbore stability challenges and the potential for unexpected influx of formation fluids. UBD involves the use of specialized equipment such as BOPs, RCDs to manage the hydrostatic pressure of well and control the influx of formation fluids. In conclusion, a comprehensive understanding of UBD is essential for maximizing hydrocarbon recovery alongside a commitment to operational safety and environmental sustainability in the ever- changing landscape of the oil and gas industries.

An Overview of How the Petrophysical Properties of Rock Influenced After Being Exposed to Cryogenic Fluid

Exposure to cryogenic liquids can significantly impact the petrophysical properties of rock, affecting its density, porosity, permeability, and elastic properties. These effects can have important implications for various applications, including oil and gas production and carbon sequestration. Cryogenic liquid fracturing is a promising alternative to traditional hydraulic fracturing for exploiting unconventional oil and gas resources and geothermal energy. This technology offers several advantages over traditional hydraulic fracturing, including reduced water consumption, reduced formation damage, and a reduced risk of flow-back fluid contamination. In this study, an updated review of recent studies demonstrates how the thermal shock caused by the cryogenic liquid during the fracturing process substantially affects the rock's physical properties. Additionally, changes in permeability, porosity, and pore structure brought about by cryogenic treatments are highlighted. This work aims to draw attention to the studies that deal with the effect of thermal shock on rock petrophysical properties and establish the ideal conditions for employing cryogenic liquids in these contexts. Simulation studies, laboratory trials, and field application cases have been undertaken to assess the efficacy of cryogenic liquid fracturing technology. These investigations have provided important insights into the physical and mechanical impacts of thermal shock on rock and the performance of cryogenic liquid fracturing in real-world situations.

A Perspective on the Prospect of Pickering Emulsion in Reservoir Conformance Control with Insight into the Influential Parameters and Characterization Techniques

In reservoir conformance control, polymer gels and foams are majorly used; however, they have drawbacks such as inducing formation damage, having weaker shear resistance, requiring a higher pumping rate, and limited penetration depth. Emulsions are a potential alternative that can address these issues, but they are not widely used. Current surfactant-based emulsions require high emulsifier concentrations for stability and often rely on multiple additives to address various factors, which makes the surfactant synthesis and utilization of emulsions quite challenging. However, Pickering emulsions, which utilize solid particles for emulsion stabilization, have emerged as a promising solution for reservoir conformance control. Compared to conventional polymer gels and foams, Pickering emulsions offer superior shear resistance, deeper penetration, and reduced formation damage. This review provides an overview of recent developments in the utilization of Pickering emulsions for conformance control, highlighting important parameters and characteristics that must be considered during the design and deployment of a Pickering emulsion for water shut-off operation. This review also sheds light on current challenges and provides recommendations for future development of the particle-stabilized colloid system.

The effect of surface properties of silicon dioxide nanoparticle in drilling fluid on return permeability

The oil and gas industry faces significant challenges in drilling and completion operations, particularly with respect to formation damage and wellbore instability. One approach to mitigating these issues is the use of nanoparticle-enhanced drilling fluids, which can improve fluid filtration and reduce formation damage. However, the influence of nanoparticle surface properties on these effects is not well understood. Therefore, the aim of this study is to investigate the influence of the zeta potential of nanoparticles in drilling fluids on the filtration of drilling fluids and its effect on the permeability of porous media. The motivation behind this work is to enhance the understanding of the role of nanoparticle surface properties in improving drilling fluid filtration and reducing formation damage. The novelty of this work lies in the exploration of the influence of nanoparticle surface properties on the return permeability of porous media. Silicon dioxides were used to represent the nanoparticles, and the surface was modified by silanization with a carboxyl group. Filtration and permeability alteration were analyzed using return permeability experiments on Berea sandstone cores under overburden pressure, pore pressure, overbalance pressure, and temperatures of 3000 psi (20.68 MPa), 1000 psi (6.89 MPa), 500 psi (3.45 MPa), and 140 °F (60 °C), respectively. Bentonite-free water-based drilling fluid and sodium chloride brine were used to represent the formation fluids. The results show that the addition of non-functionalized SiO2, and low and high carboxyl functionalized SiO2 reduced the filtration by 13%, 33%, and 36%, respectively. Although the addition of nanoparticles into the drilling fluid can reduce fluid invasion into the porous media, solid invasion into the porous media can be detrimental and cannot be easily remediated in recovering return permeability. Return permeability of porous media after exposure to drilling fluids without nanoparticles and with non-functionalized SiO2 decreased by 47% and 82%, respectively. In contrast, exposure to drilling fluid with low and high carboxyl functionalized SiO2 decreased only by 21% and 15%, indicating the importance of nanoparticle surface properties in increasing the return permeability of porous media.

Artificial Neural Network Model to Predict Filtrate Invasion of Nanoparticle-Based Drilling Fluids

Mud filtrate invasion is a vital parameter that should be optimized during drilling for oil and gas to reduce formation damage. Nanoparticles (NPs) have shown promising filtrate loss mitigation when used as drilling fluid (mud) additives in numerous recent studies. Modeling the influence of NPs can fasten the process of selecting their optimum type, size, concentration, etc. to meet the drilling conditions. In this study, a model was developed, using artificial neural network (ANN), to predict the filtrate invasion of nano-based mud under wide range of pressures and temperatures up to 500 psi and 350 °F, respectively. A total of 2,863 data points were used in the development of the model (806 data points were collected form conducted experiments and the rest were collected form the literature). Seven different types of NPs with size and concentration ranges from 15 to 50 nm and 0 to 2.5 wt%, respectively, had been included in the model to ensure universality. The dataset was divided into 70 % for training and 30 % for validation. A total of 6,750 different combinations for the model’s hyperparameters were evaluated to determine the optimum combination. The N-encoded method was used to convert the categorical data into numerical values. The model was evaluated through calculating the statistical parameters. The developed ANN-model proofed to be efficient in predicting the filtrate invasion at different pressures and temperatures with an average absolute relative error (AARE) of less than 0.5 % and a coefficient of determination (R2) of more than 0.99 for the overall data. The ANN-model covers wide range of pressures, temperatures as well as various NPs’ types, concentrations, and sizes, which confirms its useability and coverability. HIGHLIGHTS Artificial neural network (ANN)-model was developed to predict the volume of filtrate of water-based mud (WBM) modified with nanoparticles (NPs) A total of 2,863 data points were collected to build the ANN-model from both experimental work and literature considering 3 types of WBM modified with 7 types of NPs (SiO2, TiO2, Al2O3, CuO, MgO, ZnO, Fe2O3) with size and concentration ranges from 15 to 50 nm and 0 to 2.5 wt%, respectively, under wide range of pressures and temperatures up to 500 psi and 350 °F A total of 6,750 different combinations for the model’s hyperparameters were evaluated to determine the optimum combination and the N-encoded method was used to convert the categorical data into numerical values The ANN-model proofed to be efficient with an average absolute relative error (AARE) of less than 0.5 % and a coefficient of determination (R2) of more than 0.99 for the overall data GRAPHICAL ABSTRACT

Permeability Characterization and Its Correlation with Pore Microstructure of Stress-Sensitive Tight Sandstone: Take Chang 6 in Ordos Basin for Example

Tight reservoirs are sensitive to stress changes during fracturing and oil and gas production. Facing different production modes, the variation characteristics of rock permeability and pore structure need to be further clarified. In this study, using a self-built high temperature and pressure physical simulation device and NMR equipment, the influence of the stress loading method, cyclic loading, and loading rate on rock permeability and pore characteristics were analyzed, and the relationship between them was clarified. The permeability sensitivity under variable confining pressure (63.3%) was greater than that of variable flow pressure (46.4%). The damage rate decreased with repeated loading (63.3%-35.8%) and increased loading rate (53.1%-42.3%). As for the pore features, when the net stress increased, the volume variation range of micropores was greater than that of mesopores. The damage rate of permeability (63.3%) was obviously larger than that of pore volume (10.4%). The slope of the fitted curve of permeability and pore volume decreased evidently with loading times. The structure deformation of rock skeleton and the migration of cement had a great influence on permeability in the first loading. Later, it was mainly the bulk deformation of rock particles, the particles’ contact surface increasing and the seepage space shrinking slowly. Eventually, the permeability remained stable due to the limited pore compression. This study can provide a reference for designing reasonable production parameters and reducing formation damage.

Carbon-based nanocomposites: Distinguishing between deep-bed filtration and external filter cake by coupling core-scale mud-flow tests with computed tomography imaging

Although Multi-Walled Carbon NanoTubes (MWCNTs) are found to influence the rheological behavior of drilling fluids, there are yet some controversies regarding their performance towards reducing formation damage induced by the invasion of water-based drilling fluids (WBFs). To address this important question, we synthesized novel nanocomposite materials via modifying the MWCNT via varying the proportion of carboxylated MWCNTs to PolyVinyl Alcohol (PVA). These nanocomposites were then used to make nano-based drilling-fluids (NDFs). The performance of the NDFs was evaluated by a set of rheological behavior tests, filtration experiments, and core-scale mud flow tests. To distinguish between the internal and external damages made by the drilling fluid, computed tomography (CT) scanning was performed during the mud flow tests. The best yield stress (YP) and plastic viscosity (PV) were achieved at a 1:36 proportion of carboxylated MWCNTs to PVA (named as PVCNT-3). While the bulk rheological measurements (by varying the concentration of the nanocomposites between 0 and 0.6 wt%) showed a sharp increase in both YP and PV, the filtration tests showed contrary results. Independent of the nanocomposite content, the filtrates were also completely clear, demonstrating that PVCNT-3 acts as an efficient water-clay separation filter. NDFs containing a lower amount of PVCNT-3 (0.1–0.3 wt %) showed a noticeably lower degree of formation damage and a thicker external (impermeable) filter cake as confirmed by the CT scan images taken during the mud flow tests. However, high concentration of nanocomposites was found to cause significant internal pore plugging and formation damage. The results highlight the advantage of coupling core-scale tests with in-situ imaging to unravel the types of damages induced by the mud: build-up of an impermeable mud cakes (external damage) or deep-bed filtration (internal damage). This information is very essential for building proper models which capture different types of damages induced by drilling fluids.

Development and Evaluation from Laboratory to Field Trial of a Dual-Purpose Fracturing Nanofluid: Inhibition of Associated Formation Damage and Increasing Heavy Crude Oil Mobility.

This study aims to develop and evaluate fracturing nanofluids from the laboratory to the field trial with the dual purpose of increasing heavy crude oil mobility and reducing formation damage caused by the remaining fracturing fluid (FF). Two fumed silica nanoparticles of different sizes, and alumina nanoparticles were modified on the surface through basic and acidic treatments. The nanoparticles were characterized by transmission electron microscopy, dynamic light scattering, zeta potential and total acidity. The rheological behavior of the linear gel and the heavy crude oil after adding different chemical nature nanoparticles were measured at two concentrations of 100 and 1000 mg/L. Also, the contact angle assessed the alteration of the rock wettability. The nanoparticle with better performance was the raw fumed silica of 7 nm at 1000 mg/L. These were employed to prepare a fracturing nanofluid from a commercial FF. Both fluids were evaluated through their rheological behavior as a function of time at high pressure following the API RP39 test, and spontaneous imbibition tests were carried out to assess the FF’s capacity to modify the wettability of the porous media. It was possible to conclude that the inclusion of 7 nm commercial silica nanoparticles allowed obtaining a reduction of 10 and 20% in the two breakers used in the commercial fracture fluid formulation without altering the rheological properties of the system. Displacement tests were also performed on proppant and rock samples at reservoir conditions of overburden and pore pressures of 3200 and 1200 psi, respectively, while the temperature was set at 77 °C and the flow rate at 0.3 cm3/min. According to the effective oil permeability, a decrease of 31% in the damage was obtained. Based on these results, the fracturing nanofluid was selected and used in the first worldwide field application in a Colombian oil field with a basic sediment and water (BSW%) of 100 and without oil production. After two weeks of the hydraulic fracture operation, crude oil was produced. Finally, one year after this work, crude oil viscosity and BSW% kept showing reductions near 75% and 33%, respectively; and having passed two years, the cumulative incremental oil production is around 120,000 barrels.

Application of underbalanced tubing conveyed perforation in horizontal wells: A case study of perforation optimization in a giant oil field in Southwest Iran

Underbalanced perforation can substantially reduce formation damage and improve the efficiency of production operation. The field in question is a giant oil field in Southwest Iran, with over 350,000 bbl/day production rates. Reservoir X is the main reservoir of the field and includes 139 horizontal wells out of the total of 185 production wells drilled in the field. Despite its technical difficulties, under-balance perforation has been proven to result in high productivity ratios and has been shown to reduce workover costs if appropriately conducted. Therefore, this study investigated a customized underbalanced tubing conveyed perforation to enhance oil production. First, post-drilling formation damage was estimated using Perforating Completion Solution Kits. Next, high-density guns (types 73 and 127) with high melting explosives were selected based on the reservoir and well specifications. angles of 60◦ and 90◦ , shot densities of 16 and 20 shots per meter, perforation diameters of By conducting a sensitivity analysis using schlumberger perforating analyzer program, shot 8 and 10 mm, and helix hole distribution were selected as optimized perforation parameters and resulted in productivity ratios up to 1.18. The current study provides a case study of applying a combination of two previously proven technologies, tubing convoyed and underbalanced perforation, in Iran’s giant oilfield. The method used and the outcome could be used to analyze the efficiency of applying the technology in other green or mature fields. Cited as: Mohammadian, E., Dastgerdi, M. E., Manshad, A. K., Mohammadi, A. H., Liu, B., Iglauer, S., Keshavarz, A. Application of underbalanced tubing conveyed perforation in horizontal wells: A case study of perforation optimization in a giant oil field in Southwest Iran. Advances in Geo-Energy Research, 2022, 6(4): 296-305. https://doi.org/10.46690/ager.2022.04.04

Biopolymeric formulations for filtrate control applications in water-based drilling muds: A review

The forthcoming future of environmental protection mandates the utilization of naturally abundant, biodegradable, sustainable and ecofriendly materials for a wide variety of applications. Fluid loss behavior is considered the most severe problem in oil and gas well drilling operations. Because several other issues are associated with it. As a working way out, viscosifiers and fluid loss additives are introduced to the mud for rheology and filtration characteristics improvements, respectively. Polymers and starches are commonly added to base fluid to increase viscosity and reduce fluid loss of a mud. In this paper, the utilization of biopolymers used in the drilling fluid industry for filtrate reduction has been addressed. This review further emphasizes on the recent developments in native and modified starches utilization in drilling fluids extracted from various sources and the present research gaps for future developments. The utilization of biopolymers as potential additive in nondamaging water-based muds have been addressed to reduce the impacts of mud filtrate in the exposed formations. Moreover, various factors that influence the effectiveness of biopolymers and the utilization of such polymers in different muds are also discussed. The filtration characteristics in terms of filtrate volume and filtercake thickness generally showed improvements by using biopolymers. Filtercakes generated from starch-containing muds have been found to be thinner and more compact, resulting in reduced formation damage due to lower mud particle penetration.

Modified smart water flooding for promoting carbon dioxide utilization in shale enriched heterogeneous sandstone under surface conditions for oil recovery and storage prospects.

Modern oil reservoirs exhibit high macro-scale heterogeneity, i.e., presence of shales and clays, which complicate the implementation of conventional enhanced oil recovery (EOR) practices. Hence, there is a need to investigate new class of EOR methods which not only improve recovery of oil from reservoir but also reduce formation damage. Thus, in this study, synthetic smart brines of varying salinity were formulated to investigate carbon utilization in shaly-sandstone for oil recovery and sequestration applications. To prepare shaly-sandstone samples, shale content in sand varied between 0 and 25 wt%. The addition of shale reduced porosity and permeability of sand-packs, and porosity ~ 25 and permeability < 10 md were measured for a combination of 75% sand + 25% shale which were originally 38% and 692 md for 100% sand + 0% shale. The oil recovery experiments were performed at temperature ≈ 40°C and ambient pressure. The impact of shale content was insignificant on CO2-based oil recovery resulting its value remained nearly constant (5-7%). Smart saline water (SSW) solutions were prepared through the dilution of formation water (FW) of typical oilfield salinity and used these SSW solutions in investigating shale swelling and interfacial tension with CO2. Compared to other SSW solutions, SSW-2 (1 part FW/9 part water: 1/10th of FW) demonstrated superior control on mitigating shale swelling (by 67%) and reduce interfacial tension (by 30%) when compared to FW. Moreover, it helped to mobilize higher amount of oil (50% OOIP) from sand-pack (80% sand + 20% shale) in which conventional water flood failed to perform, indicating its viability for EOR from heterogeneous reservoir. In addition, SSW solutions promoted use of carbonated (CO2-enriched) water injection for oil recovery from sandstone exhibiting high shale content of 20% as over 5-8% higher oil recovery was obtained compared to conventional water flooding. Comparative performance of water flooding, salinity water-alternating CO2 flooding and carbonated smart water injection in heterogeneous sandstone.

Experimental study and modeling of final fracture conductivity during acid fracturing

Successful acid fracturing operation could reduce formation damage and increase production rate in a carbonate reservoir. Final fracture conductivity is a critical parameter that determines the success of the acid fracturing operation. A wide range of parameters could affect the fracture conductivity, making its prediction quite difficult. The effect of contact time, type of acid, and rock type has been evaluated before. In this study, however, the effect of concentration of hydrochloric acid (HCl), rock strength, injection rate, acid type, and rock type on the conductivity of the fracture was investigated. Based on our observations, for calcite rock types, greater fracture conductivities were achieved by using HCl 15% compared to HCl 7%. For dolomite, the result was completely different and lower concentration of HCl had better outcome. Depending on the type of acid that was used, different results achieved for rocks with different strength. When low concentration of HCl, HCl 7%, was used as an injection fluid, dolomite with higher strength had better conductivity. However, for strong acid, HCl 15% and emulsified acid, the best results were obtained for calcite with low strength. Injection rates resulted in two different outcomes. At low concentration, the injection rate of 4 ml/min created better fracture conductivity while at high concentration, the injection rate of 10 ml/min generated better results, when injection fluid was HCl. As for emulsified acid, higher injection rate resulted in proper conductivity. In most cases, emulsified acid had better final fracture conductivity. Based on experimental results obtained, three models for three different acid types were developed. The conductivity of rocks after acid etching was predicted based on injection rate, rock strength, and closure stress. Statistical and graphical analysis proved that developed models have a good performance.

Estudio piloto para la inyección de bactericidas en arenas con problemas de actividad microbiana en el Campo Libertador, Bloque-57

Microbial activity can lead to problems such as corroded tubing, formation plugging, and decreased effective permeability, especially the sulfate-reducing bacteria that have the formation water as a medium that allows their proliferation. These adhere to the conductive channels of the producing sand and form biomass that restricts the flow of fluids. This work was carried out to design a non-reactive matrix stimulation by injecting biocides that clean the sand face to increase permeability, reduce formation damage, control corrosive environments, and increase daily oil production. By analyzing the total concentration of iron, sulfate, carbon dioxide, sulfide in gas and water, wells with microbial activity were identified, while the behavior of the bacteria was characterized by evaluating bacterial cultures and corrosion coupons. Using economic profitability criteria, the TTT A 011 and TAP 09 wells were selected as the most prospective in the Libertador field since, out of the 94 wells analyzed, they presented the highest index of microbial activity and recovery of oil barrels. The microbial activity in the wells of the Tetete station is more aggressive, since they reproduce in less time, clogging the porous channels at a faster rate. The THPS and GLH bactericides had better functionality against bacteria and the environment, so they were considered in this design of non-reactive matrix stimulation generating $907,976.10 as profit for the company in the 12-month projection.

Effect of Two Types of Fly Ash on Rheological and Filtration Properties of Water-Based Drilling Mud

In this study, the usage of class F fly ash (brown coal) and class C fly ash (lignite) with increasing concentration in water based mud mainly composed of bentonite dispersion was investigated at ambient conditions. Experimental results indicate that efficiency of the mud is significantly controlled by type of the fly ash tested and its concentrations. The results show that Class F fly ash enhanced filtration properties (filtrate loss and mud cake) of the mud and have no effect on the rheology including, yield point, viscosity whereas the class C fly ash increased the rheology parameters and degraded water loss into the formation and filer cake thickness dramatically. This study showed that class F fly ash displays superior performance than class C fly ash. Through this study, it was reveal that class F fly ash is a promising additive to improve the filtration characteristics of bentonite based drilling fluids, thereby contributing to reducing formation damage caused by drilling mud.

Fluid Loss Control in Water Base Mud Using Ferric Oxide Nanoparticles and Local Additives

The success of well drilling operations is heavily dependent on the drilling fluid because drilling fluids cool down and lubricate the drill bit, remove cuttings, prevent formation instability, suspend cuttings and also cake off the permeable formations, thus retarding the passage of fluid into the formation. During drilling operations, the fluid part of the drilling fluid may be lost to the formation, a huge fluid loss lead to higher operational expenses. That is why, it is vital to design the drilling mud to minimize the mud invasion in to formation and prevent fluid loss. This study focused on improving the performance of water base drilling mud by the usage of ferric oxide nanoparticles and local additives such as corn cob powder from zea-mays and coconut husk powder from cocos nucifera as fluid loss control additives in the drilling mud. The laboratory measurements included measuring the filtrate loss using the standard API low temperature low pressure (LTLP) filter test, some properties of the mud such as the mud density and pH were measured using respective apparatus. Also, the filtration properties of water-based nano and local additive drilling fluids under static conditions were investigated. It was seen from the results that the lowest filtrate loss value of 14.4ml occurred for an addition of 1.0g of ferric oxide nanoparticles acting alone as the fluid lost material. Under API standard filtration test at LTLP, more than 70% reduction in fluid loss was achieved in the presence of 0.5 - 1.5 wt% nanoparticles. The results have also shown that the filter cake developed with the nano and local additive mud indicate thin filtration, which implies high potential for reducing the differential pressure sticking problem, as well as reducing formation damage and torque and drag problems while drilling. Nanoparticles (NPs) based drilling mud with specific characteristics is thus expected to play a promising role in controlling the fluid loss and other technical challenges faced with commercial drilling mud during oil and gas drilling Keywords: Coconut Husk, Corn Cobs, Drilling Mud, Ferric Oxide, Filtrate Loss, Fluid Loss Additive, Mud Cake Thickness, Nanoparticles DOI: 10.7176/CER/13-6-03 Publication date: October 31 st 2021