Abstract Graphene as surfactant carrier material for EOR/IOR is used. Its performance is evaluated through adsorption, desorption, interfacial tension and emulsification studies. Moreover, the kinetic and thermodynamic parameters are identified in order to understand the physicochemical behavior pertaining to its applicability in surfactant flooding. The surfactant carrier, graphene is acquired and its physicochemical behavior is characterized by X-Ray diffraction, Fourier transform infrared spectroscopy, surface area analysis, etc. The uptake capacity of the surfactant is investigated by adsorption and desorption studies at different subsurface conditions. The kinetics of the process are identified to understand the rate and order of the reaction, whereas thermodynamic behavior of the surfactant carrier is evaluated to find its Gibbs free energy, enthalpy, entropy, activation energy, etc. Further, a reduction in interfacial tension and stability of emulsion between crude oil and brine is inspected. The uptake capacity of the surfactant obtained from the adsorption and desorption study confirmed that adequate quantities of surfactant can be transported into the deep subsurface with minimal loss. This infers the requirement of surfactant in lesser quantity when compared to surfactants without any nanocarrier. Similarly, a reduction in interfacial tension and increase in emulsion stability is expected to be increased. Furthermore, graphene shows a remarkable change in hydrophobicity with a change in pH and salinity which indicates that the properties can be suitably tailored as per requirement, making it a good candidate for surfactant EOR/IOR. Also, the obtained thermodynamic data suggest endothermic and spontaneous adsorption behavior, which may be a favorable phenomenon when subjected to the higher subsurface temperature. Graphene as a surfactant carrier and its performance is investigated for the first time rendering it unique for EOR/IOR applicability studies.

Abstract Chemical enhanced oil recovery (EOR) is a method that helps to increase recovery of oil in the tertiary stage of a reservoir. Methods such as polymer, surfactant, and microbial injection increase overall recovery by producing unswept or residual oil that remains after a water flood. The primary goal of this research was to simplify the calculations needed to predict polymer rheology and to model polymer behavior without the need for lab testing samples. Polymer samples with varying concentrations, salinities, and hardness levels were prepared and polymer viscosity versus shear rate was measured using a rheometer. It was found that polymer preparation methods significantly affect the rheological properties of a sample and standard procedures ensure consistency. Predictive calculations were performed before lab testing samples so that the lab data could be compared to various models in order to determine their accuracy. A program was created to find constants of the polymer and to model polymer viscosity versus shear rate. This program also includes fitting parameters (specific for polymer type) that allow these calculations to be performed without the need for lab fitted data. Polymer rheology is dependent on a sample's composition, and its rheological properties can be easily and accurately modeled by the developed program. Various outdated programs relating to polymer EOR were also updated to meet modern standards and to improve their functionality.

Waterflood conformance is a significant problem in the West Sak field of Alaska. Re-assembling Pre-Formed Particle Gels (RPPG) have been used to treat Void Space Conduits (VSC) and repair the "short-circuited" waterflood. These VSC’s are typically formed by sand producing wormholes. Several dozen VSC solutions have been implemented since 2006, including molten wax, cement blends, and pre-formed particle gels. To date, all the solutions have been faced with various limitations due to the low reservoir temperature and poor sand consolidation. A good percentage of the pre-formed particle gel (PPG) solutions have been successful in sealing off VSCs, but often show limited longevity that can range from as little as several weeks to several years. An effort was undertaken to develop a product that would provide enhanced stability in the VSC and extend solution life beyond the current range. A cost-effective conformance solution was developed with increased mechanical strength through a re-crosslinking process known as RPPG. The goal of the RPPG solution is to provide a longer-term repair to a VSC and restore the primary water flood characteristics. This paper will present the results of the seventeen RPPG solutions that have been pumped between 2017 and 2019 in the West Sak field on the North Slope of Alaska. RPPG treatments have shown a 23% improvement over traditional PPG treatments at the economic payout during the field trial. There have been some significant learnings through this time period. The focus of this paper will be to review the VSC problem understanding and the reason for the RPPG product development, detail the evolution of RPPG job design over time and provide results and operational knowledge from the field trial efforts. The latest advancements in conformance engineering will be of interest to Reservoir and Production Engineers who are focused on supporting and optimizing conventional waterflooded assets, particularly when faced with conformance issues in an unconsolidated reservoir. In addition, the field results will be useful to those seeking to implement RPPG solutions in their area of operation.

This paper presents a method of using chemical tracer data to quantitatively evaluate interwell communication in various well configurations by combining raw tracer data with field production data. Qualitatively, tracer breakthrough in an offset well indicates that there is communication between the infill and primary well, but by utilizing the method described in this paper, the fracture driven interaction (FDI) severity can be quantified by determining the total mass of tracer produced out of the primary well and new wells. The technique yields an allocation of load fluid and hydrocarbon recovery at each well and associated formation.

The US Department of Energy and Hilcorp Alaska, LLC are jointly cosponsoring a field pilot project entitled "First Ever Field Pilot on Alaska’s North Slope to Validate the Use of Polymer Floods for Heavy Oil Enhanced Oil Recovery (EOR)." The objective of this pilot is to perform a field experiment to validate the use of an advanced polymer flooding technology to unlock the vast heavy oil resources on Alaska North Slope (ANS). Two pairs of horizontal injection and production wells have been deployed in an isolated fault block of the Schrader Bluff heavy oil reservoir at the Milne Point Field to conduct a polymer flood pilot which was designed to acquire field performance data to optimize polymer flood design in the Schrader Bluff heavy oil reservoirs on ANS. Hydrolyzed polyacrylamide (HPAM) polymer injection started on August 28, 2018 using a custom made polymer mixing and pumping unit. Polymer solution properties such as concentration, viscosity, and filter ratio, have been closely monitored and adjusted as necessary. Operational procedures have been improved to ensure adequate injectivity and polymer propagation through the formation. Oil and water production is tested frequently to monitor water cut performance, and produced water is sampled and analyzed for polymer content. Tracers were pumped pre and post polymer injection startup to compare polymer flood breakthrough timing and sweep efficiency. Polymer injectivity of the horizontal wells drilled in the Schrader Bluff NB sand is found to be sufficient to replace the reservoir production voidage although there were some declines as high viscosity polymer swept the near wellbore region. Production data show significant reduction in water cut and increase in oil production rate. No polymer production has been confirmed from the two horizontal producers after 23 months of polymer injection into the two supporting horizontal injectors. Tracer data show very low sweep efficiencies with waterflood alone, whereas significant improvement has been achieved with polymer flood. Many operational lessons have been learned and improvements have been made regarding polymer mixing, pumping, and onsite quality control, particularly in a challenging Arctic environment. Adequate polymer injection rate can be achieved with diligent monitoring and quality assurance of the properties of the injected polymer solution.

The success of a fracturing treatment and long-term productivity highly depend on the residual proppant pack conductivity over time. One of the challenges operators face is the conductivity loss due to proppant flowback or sand production during production operations. As proppant particles come out of the fracture along with the production, the fracture conductivity diminishes with time as the fracture width decreases. This choking effect causes well production decline while the high-velocity low-concentration proppant particles wreak havoc on both downhole and surface equipment. As a result, proppant flowback costs millions of dollars through loss of production and expensive equipment damage. Wells experiencing these problems require remediation ranging from routine wellbore cleanouts to expensive artificial lift equipment repairs. Hydraulic fracturing became the mandatory stimulation technique to economically produce hydrocarbons in mature fields. However, proppant flowback following the fracturing treatment has been a major concern because of its detrimental effect on production equipment, leading to plugging or erosion of surface and downhole completions. The net impact of proppant flowback can be reduced production, damaged equipment, and downtime. This has prompted a detailed integrated study including both laboratory testing and development of the necessary numerical simulation models to fully understand the post-fracturing proppant flowback mechanism. Resin-coated proppant (RCP) was originally developed for post-fracturing treatment proppant flowback control. However, RCP requires a specific temperature trigger to get activated, which puts some restriction on the RCP application range. In addition, RCP requires prolonged shut-in time, which may cause issues with well cleanout, and RCP is relatively expensive. Another innovative solution that can be used for flowback control in certain conditions is a new flowback technology with nondegradable fiber proppant, designed specifically for low-temperature applications. This technology provides extraordinary proppant-pack integrity by interlocking proppant grains in a flexible 3D network. The grains do not require temperature activation and so perform equally well at any temperature below 200°F, both in oil and gas reservoirs. The fibers can be applied with any proppant (sand or ceramic), and they keep the proppant consolidated even at stress cycling conditions. Unlike RCP or other chemical treatment method, the nondegradable fibers rely on mechanical interference of the particles and not on chemical bonding. The key advantages of this technology are that consolidation is not dependent on activation temperature or time, and the proppant does not interfere with fracturing fluids or additives such as breakers that are known to be adversely affected by the presence of resin material. This paper presents the results of extensive laboratory evaluation and numerical simulation models of fiber performance, as well as global field case histories of successful application of the fiber as a solution for proppant flowback control in low-temperature environments. In all wells, remedial work has significantly dropped due to the excellent proppant flowback control. Meanwhile, the proppant flowback issues have been completely stopped, which led to remarkable success.

Since 2015, scale problems have appeared when gas production decreased below 30 Mm3/day and wells could not evacuate liquid and solids to the surface due to liquid loading. Scale depositions were found in casing and tubing at different depths close to Quintuco Formation perforations. During 2019, more than 30 wells were mechanically cleaned using slick line to remove scale every 30 days approximately. This paper describes the study of the origin of scale in gas wells producing from multiple formations and the chemical technology applied to solve this problem in the mature urban field Centenario (Neuquén - Argentina). Core and water analysis were performed to study the scale phenomenon at the productive formations and to determine the compatibility between fracturing and formation waters. In addition, it established the scale origin and served to detect further wells susceptible to suffer scaling problems. Scale is produced in the casing, not in the formation, due to changes of pressure and temperature related to the expansion of gas and changes in water mix compatibility at Quintuco perforations depth. Due to the field location, subsurface safety valves were installed in the tubing to prevent possible blowouts. Thus, capillary string for product injection was discarded. A proven chemical technology for oil wells-encapsulated scale inhibitors-was adapted to treat gas wells aiming for a treatment duration of three months. The method consisted of a mechanical clean-up followed by a batch treatment of encapsulated product with water and, finally, a slick line run to ensure it reached the bottom-hole. The chemical treatment pilot was carried out in 6 wells. Candidates were selected based on abnormal production decline, scales showed after slickline intervention, favorable response after mechanical clean-up, and high intervention frequency. The pilot held in 2019 showed an increase in gas rate production of 12 Mm3/day on average representing 40% of well production, high stability in gas production and a reduction of slickline intervention frequency. The duration of the treatment was initially estimated according to the liquid rate of the well and the product concentration used. During 2020 the pilot will be expanded to 32 wells in the field. Solid scale inhibitor for gas wells is relatively new in the industry and there is not much bibliography about application and results in this type of wells. This paper describes the methods used for scale characterization, the prediction of its formation in gas wells, the selection method for scale inhibitors, the product application technique to the wells and the results obtained in the pilot, demonstrating its technical and economic feasibility for field use.

We present thermodynamic modeling and pH measurements of fluid systems containing acid-gases (e.g. CO 2 and H 2 S), water and hydrocarbons – replicating the production and shutdown conditions in sour fields – for the purpose of evaluating top-of-line corrosion and wellbore integrity, and screening/selection of the proper wellbore materials. In particular: An EOS model using Peng-Robinson EOS in combination with Huron-Vidal mixing rule for aqueous sub-system is developed. In the model, subject EOS parameters are calibrated against existing thermodynamic data (saturation data for pure components and solubility data for binary systems) in literature. A new in-situ pH measurement data is presented for a model system corresponding to sour field. It was found that the wellbore can be subjected to pH levels as low as 2.7 with reservoir fluid containing 12 mol% CO 2 and 88 mol% methane with downhole flowing conditions of 200 bar and 150°C, and wellhead shut-in conditions of 300 bar and 4°C, as observed from the experiments. A modeling workflow is developed to estimate pH of the condensed water as a function of temperature and composition of the aqueous phase. The comparison between prediction and experimental measurement show very good match between the two (within pH ±0.1). Such studies (pH measurements and prediction) are not available in literature but play important role in material screening and assuring wellbore integrity for sour fields. More importantly, sensitivity analysis can be performed to investigate the effects of various factors (such as reservoir temperature/pressure, shutdown conditions, and compositions or extent of souring) on pH prediction. Furthermore, the methodologies developed through this work can also be extended to reservoir facilities, pipelines, sour gas disposal/handling units, as well as, downstream systems such as as water-utilities, reactor plants and refineries. The work can also support for regulation/licensing for these sour systems.

In a recent paper ( Yang et al., 2019a ), we published a machine learning method to quantitatively predict reservoir fluid properties from advanced mud gas (AMG) data. This approach has clear advantages due to early access, low cost, and a continuous reservoir fluid prediction for all reservoir zones. In this paper, we demonstrate how real time reservoir fluid logs are generated and compare the results with PVT samples or production data from the same well. We develop a workflow of generating reservoir fluid logs from AMG data and PVT database. The workflow consists of two main processes; first a quality assessment of AMG data and second the computation of reservoir fluid properties (in this paper we use gas oil ratio). The entire workflow is written in python and embedded into existing commercial petrophysics softwares. The final product of the workflow are three log tracks which we call the reservoir fluid logs and those are 1) the concentration readings of the AMG data, 2) the QC metric score, and 3) the predicted GOR log. These three logs are plotted together with other standard open hole logs such as gamma ray, neutron-density, sonic and resistivity log to get a more comprehensive formation evaluation. Reservoir fluid logs derived from AMG data has two main advantages. First, it is the only approach to acquire continuous reservoir fluid properties along the well path. The continuous fluid profile can be used to understand the variation of reservoir fluids in both vertical and lateral direction. The second advantage is that the reservoir fluid log is obtained while drilling and therefore the information can be used to optimize the drilling process or the downhole sampling program during wireline operation. In this paper, we demonstrate the application of the reservoir fluid logs in four conventional field cases. In the first study case we show the benefit of using the reservoir fluid logs in a horizontal well as a substitute for downhole fluid sampling. In the second case study, we demonstrate how the reservoir fluid log is utilized to optimize the downhole fluid sampling program which results in reducing the subsurface uncertainty. Next, we exhibit the use of the reservoir fluid logs to locate gas oil contact in a case where pressure data does not show clear distinction of gas and oil gradient in the reservoir. In the last example, we illustrate the use of reservoir fluid knowledge from AMG to characterizing the fluid variation across a field. The field applications demonstrate the success of the new method for conventional reservoirs, provided good-quality AMG data are available.

Monitoring of low- and high-gravity solids (LGS and HGS) content and maintaining these at ideal levels is essential for the optimum drilling fluid performance, efficient hole cleaning and ECD management, as well as preventing failures of surface and downhole equipment during drilling. LGS and HGS monitoring in the field is currently accomplished using the API retort measurement, which has certain drawbacks and is difficult to automate. In this paper, alternative approaches to solids characterization are presented that lend themselves much better to automation and real-time monitoring. Two new approaches were investigated to automate the LGS and HGS content measurements of drilling fluids, which can potentially replace the retort test in the future. In the first approach, extensive lab experiments were conducted to generate a controlled dataset that includes fluid rheological properties and density changes by the addition of various levels of LGS and HGS. Using this dataset, multi-linear, Ridge, Lasso, K-nearest neighbors (KNN), and Random Forest (RF) regression models were trained and tested to predict LGS and HGS content of drilling fluids. A key advantage of this machine learning (ML) approach is that these fluid properties can be obtained in real-time with measurements that are relatively simple and easy to automate. In the second approach, X-Ray Fluorescence (XRF) was used to generate calibration curves for various common solids used in drilling fluids (i.e., barite, clays, salts). This method also lends itself well to automation with real-time inline measurement. Side-by-side tests of various fluids were performed using the API retort measurement, the ML approach, and the XRF sensor. It was observed that the API retort measurement can provide erroneous LGS and HGS content estimations. On the other hand, the trained ML regressor provided results with an average absolute error of only 0.3%. It was also observed that with the XRF measurements, distinct solids can be tracked highly selectively by quantifying the concentration of their specific elemental compounds (i.e., barium for barite concentration, silicon for sand concentration, iron for clay concentration). A detailed comparison of the three methods (API retort, ML, and XRF) is provided, clearly showing the advantages of the ML and XRF approaches over the older retort method. The technology described here opens the doors to automated mud monitoring, maintenance, and solids control operations, which can assist with real-time solids content management and optimization. This will benefit downhole ECD management, hole cleaning optimization, ROP improvement and reduced equipment failure, resulting in safer wells drilled at lower costs.

The objective of this paper is to structure a data-driven-based workflow to design and optimize alkali-surfactant-polymer flooding ( ASP ) projects. Various objective functions from the techno-eco perspectives are considered to obtain comprehensive optimum ASP slug formulations and injection operation schemes. Several universal multi-layer neural networks ( MLNN ) are trained and they act as surrogate models of high-fidelity numerical simulation models to evaluate the objective functions involved in the optimization workflow. The input parameters considered by the machine-learning workflow include the reservoir rock and fluid properties, ASP slug formulation, and project design parameters. A physical equation of state, HLD - NAC equation, is employed to model the microemulsion phase behavior of the crude oil/brine/surfactant system. The validity of the surrogate models is confirmed via extensive blind testing applications with error margins of less than 5%. Thus, the MLNN can be employed as an expert system to assess the response functions of the ASP injection processes, including oil recovery, water cut reduction, pressure responses, etc. A hybrid global optimization workflow is structured by coupling the expert MLNN systems with particle swarm optimizer ( PSO ). Comprehensive techno-eco-assessments are carried considering the oil recovery, chemical slug utilization ratio (incremental oil production per unit mass of chemical additives), and project economics as objectives. This paper presents case studies to illustrate the robustness of the proposed workflow in optimizing the ASP injection projects considering multiple objective functions. The optimization work focuses on the design of ASP slug formulations and injection patterns. A sensitivity analysis is carried to investigate the trade-off factors between pairs of the objectives. Objective functions exhibiting a strong trade-off relationship can be included to structure Pareto front solutions, which enables the optimization workflow to find various optimized ASP formulations and injection schemes. The outcomes of this work not only provide field operators with various options to implement ASP injection processes but also generate stochastic assessments of the optimized objectives. This work develops a universal proxy model that is competent to generalize the microemulsion phase behavior that occurs in the ASP injection processes. The trade-off relationship amongst the critical objective functions is investigated via a rigorous sensitivity analysis using the proxy models. With the help of the developed model, the decision-makers can design ASP injection projects based on various project preferences. Moreover, the project risks can be understood by observing the stochastic outcomes of the optimized objective functions.

A potential enhanced oil recovery (EOR) technique is to inject alkali into a reservoir with a high total-acid-number (TAN) crude to generate soap in situ and reduce interfacial tension (IFT). The method may be cost-effective if the IFT can be lowered enough to cause significant mobilization of trapped oil, while also avoiding formation of gel/viscous microemulsions. This paper investigates the potential field application of injecting alkali to generate in situ soap and favorable phase behavior for a high TAN oil. Oil analysis results show that the acids in the crude are a complex mixture of various polar species and not mainly carboxylic acids. Phase behavior experiments show that the system does not undergo typical Winsor microemulsion behavior. Therefore, traditional microemulsion models can cause unreliable recovery estimates. The mixing of alkali and crude/brine can generate water-in-oil macroemulsions that are highly viscous instead of forming the classical Winsor types. Good core flood recovery cannot be explained by the formation of a Winsor microemulsion phase, as is expected in surfactant EOR, mainly because these macroemulsions form before such idealized phase behavior can occur. A substantial decrease in interfacial tension is observed without the formation of a viscous phase in a narrow window of alkali concentration. Corefloods with polymer perform well in this concentration range, although incremental recovery could be overestimated some owing to increased water solubility in oil within these macroemulsions. The viscous phase behavior at large alkali concentrations is likely explained by the formation of salt-crude complexes, created by acids from the crude oil under the alkali environment. These hydrophobic molecules tend to agglomerate at the oil-water interface. Together with polar components from the crude oil, they can organize into a highly viscous network and stabilize water droplets in the oleic phase. Oil-soluble alcohol was added to counter those two phenomena at large concentrations, but typical Winsor phase behavior was still not observed. A physicochemical model is proposed to explain the salt-crude complex formation at the oil-water interface that inhibits classical Winsor behavior.

Switching to utilize HVFRs has been blossomed rapidly due to enormous advantages such as the ability to carry proppant and high potential lower cost. However, challenges remain in fracking fluids rheology characteristics due to a change in water quality that leads to poor proppant transport through fractures. The primary objective of this study is to develop a mathematical model based on prior published experimental data that can be used to predict HVFRs viscosity profile as a function of essential factors. Water analysis and viscosity property characterization of the selected fracturing fluid (HVFR) were investigated to address the effect of water quality on proppant transport behavoir. In this paper, a case study of the Permian Basin produced water "high-TDS (125Kppm)" was chosen in screening criteria analysis. Also, different dosages (0.25, 0.5, 0.75, 1.0, and 2.0 gpt) of HVFRs were selected to estimate the viscosity profile in freshwater and the Permian produced water. The developed new model from this study can be used effectively to predict viscosity profile and proppant transport in HVFRs fluids taking into account fracture fluid dosage, water quality, and operation shear rate. The developed model covers HVFRs dosage ranging from 0.25 to 2.0 gpt (gallons per thousand gallons). This model can be used to assist in obtaining proppant settling velocity as a function of shear rate. The developed model shows the high accuracy of prediction HVFR viscosity profile with a low average error of 0.14% and 0.07% in freshwater and Permian produced water, respectively. This paper will help provide a full understanding of the distinct changes of the mechanical characterization on the HVFRs. The findings provide an in-depth understanding of the behavior of HVFRs under high-salinity conditions effect, which could be used as guidance for fracture engineers to design and select the optimum dosage of friction reducers.

State-of-the-art chemical flooding simulators typically use nonpredictive phase behavior and property models to design a surfactant flood. For example, a variation of the black-oil model is often used to represent phase behavior in several commercial simulators. We examine the available methods including more recent physics-based models such as the HLD-NAC equation-of-state and their effects on overall recovery, front speeds, and breakthrough times. We implement the HLD-NAC EoS model in UTCHEM to examine the impact of changing salinity and other variables on the phase behavior and the recovery process. A novel predictive viscosity model is also implemented for the first time in UTCHEM to give a more accurate prediction of viscosity. We isolate the impact of salinity and other gradients on recovery in a one-dimensional homogeneous reservoir. Results show that the composition path can enter the Winsor II+ region for certain changes in variable gradients. When the two-phase region is entered, the trailing injected fluid surpasses the chemical slug and contacts the oil bank directly. The microemulsion phase saturation is then decreased to immobile values so that surfactant is now immobile and oil recovery is significantly decreased. We further show that the presence of polymer - both in the buffer and the chemical slug - has little effect on the appearance of the arrested microemulsion and oil bank. Polymer does partially offset the negative effects by providing conformance control immediately after the microemulsion phase is trapped. The salinity gradient should be designed so that the composition path avoids the II+ lobe in its entirety, giving a robust and mobile slug with or without polymer. We propose a limit in injection salinity under which the II+ lobe can be avoided. We also show that the less accurate viscosity model overestimates recovery in a two-dimensional simulation of the chemical flood.

The complex pore structure and storage mechanism of shales make the mass transport in these ultratight reservoirs complicated and significantly different from typical conventional rocks. A substantial fraction of total pore volume in organic-rich ultratight reservoirs consists of nanopores in which the notion of viscous flow may become irrelevant. Instead, multiple transport and storage mechanisms should be considered to model fluid transport within the shale matrix, including molecular diffusion, Knudsen diffusion, surface diffusion, and sorption. This paper presents a diffusion-based semi-analytical model for a single-component gas transport within an infinite-acting organic-rich ultratight matrix. The model treats free and sorbed gas as two phases coexisting in nanopores. The overall mass conservation equation for both phases is transformed into one governing equation solely based on the concentration (density) of the free-phase. As a result, the partial differential equation (PDE) governing the overall mass transport carries two newly-defined nonlinear terms; namely, overall diffusivity, D , and sorption-corrected porosity, Φ. The D term accounts for the molecular, Knudsen, and surface diffusivity, and the Φ term considers the mass exchange between free- and sorbed-phases under sorption equilibrium condition. Both D and Φ are functions of free-phase concentration. The nonlinear PDE is solved by applying a piecewise-constant-coefficient technique that divides the domain under consideration into an arbitrary number of subdomains. Each subdomain is assigned with a constant D and Φ. The diffusion-based model is validated against numerical simulation. The model is then used to investigate the impact of surface diffusivity, Knudsen diffusivity, porosity, and adsorption capacity on gas transport within the ultratight formation. Further, the model is utilized to study gas transport and production from Barnett, Marcellus, and New Albany shales. The results show that surface diffusion significantly contributes to gas production in shales with high surface diffusivity and adsorption capacity and when the Knudsen diffusivity and total porosity are small. Thus, neglecting surface diffusion in organic-rich shales may result in the underestimation of gas production.

The Turonian siltstone found throughout the Siberian region in Russia is laminated, heterogeneous, and shaly; has permeability of 0.1 to 3.0 md; and contains hundreds of trillions cubic feet of natural gas. Hydraulic fracturing is necessary to achieve commercial production rates. Important developments have been made in optimizing a water-free fracturing fluid that can be used in similar cold and highly water-sensitive reservoirs worldwide. The study encompassed laboratory testing methodology, testing results, and field trial campaign analysis of the advanced water-free fracturing fluid. Non-Newtonian fluid rheological behavior, proppant transport ability, and fluid break under dynamic and static conditions at 60°F (15°C) were investigated and compared to conventional crosslinked water-based fracturing fluids. The field trials used a fluid recipe that enabled successful execution of very aggressive fracturing designs using large-size proppant placed at concentrations of up to 12 lbm/gal added (1400 kg/m 3 ) in multistage fracturing treatments along a horizontal wellbore. This approach was used to improve fracture conductivity and fracture cleanup while minimizing fluid costs. The most significant advancements have been made in the breaker package design for the fluid mixed in diesel fuel. Improved breaking can accelerate the flowback period and create a high-retained-conductivity proppant pack, allowing large volumes of gas to flow with minimal restriction. Additional study of proppant transport revealed the presence of elastic properties that are not common for water-based guar-borate gels. This property enabled increased proppant concentration and aggressive hydraulic fracturing designs that were successfully employed in a field trial campaign comprising three horizontal wells completed with a total of 10 fracturing operations. Multistage fracturing completions consisted of shifting sleeves for the fracturing stages and separate ports with screens for the production stage to control formation and proppant flowback. This completion enabled selective fracture cleanout, which is vital in the low-temperature geological conditions. The developed stimulation approach resulted in progressive gas production increases after stimulation. Fluid development results indicate the new diesel-based fracturing fluid delivers an improved stimulation approach for low-temperature siltstones containing a high content of sensitive clays. It is the only project we have seen in the literature with a successful diesel-based fracturing fluid application in extremely low-temperature geology. Although developed for Russian fields, the work is equally applicable to any water-sensitive, shaly, low-temperature reservoir globally.

An application for Pressurized Mud Cap Drilling (PMCD) was needed to successfully drill an U.S. onshore, unconventional, High Pressure / High Temperature (HP/HT) well. The length of the lateral, highly fractured formation & extremely high MWs needed to drill the lateral proved that conventional drilling methods would not be effective, so PMCD was utilized. The main challenge was to keep circulating pressures low while injecting the circulating fluid into the naturally highly pressurized formation. PMCD involves injecting / losing the circulating fluid (water) into the formation, in this situation, high formation fracture pressures required high surface injection pressures to push the fluid & cuttings into the formation. When the injection pressure was combined with the frictional losses through the drill string, anticipated surface pressures were over 10k psi when circulating. To combat the high circulating pressure, an approach was taken to use Friction Reducer (FR) in the circulating fluid, water, thus reducing the frictional pressure loss while circulating within manageable constraints. This paper will go into detail of the different phases taken to determine the appropriate type of FR based on lab testing, hydraulics model, temperature modeling, and the results from the application of the product in the drilled well. Extensive hydraulics modeling was conducted to determine the feasibility of using the FR and the final anticipated circulating pressure. The BHA and drill string design was optimized to maximize the least amount of pressure drop across the tools while staying within operating parameters. Concerns of the use of FR such as ECD effect, fluid flow characteristics for hole cleaning in the annulus, temperature effects of the water being pumped, and effects in the BHA were all considered in the engineering process. FR testing including, lab testing of the base fluid (water), differential scanning calorimeter to determine effects of BHT, FR shear testing, FR concentration percentage at various flow rates in a flow loop to calculate Reynolds number at the respective flow rates & concentration and differential pressure testing with time and temperatures. Based on the results from the hydraulics modeling and lab tests, an FR was selected and fully utilized in the application of the product. PMCD techniques with this FR was used and was fully successful in the intended reduction of the surface circulating pressures while drilling the well. Surface and downhole results captured the effects of the FR in the fluid system and data was collected and analyzed to show the expected vs actual results on various drilling parameters.

Achieving mobility control of steam in porous media has been approached by the implementation of foaming surfactant additives; however, foam generated with surfactants lack stability at high temperatures (≥ 200 °C). In this study, a nanofluid was formulated for steam co-injection to address common issues with surfactants as steam additives. The nanofluids were formulated using synergistic interaction of nanoparticles and surfactants (both readily available) to address thermal stability, and foam stability at the conditions encountered in thermal enhanced oil recovery processes such as steam assisted gravity drainage. Zeta potential analysis, static tests, and high temperature aging tests were performed to obtain the ideal mixture of nanoparticles and surfactants. A steam/foam core flooding apparatus was used to evaluate the mobility reduction of nanofluids using multiple differential pressure transmitters situated along the length of a 40 cmsand pack to confirm foam propagation. The tests were first conducted at 200 °C with nitrogen as a non-condensable gas carrier. Upon confirming nanofluid mobility reduction characteristics at 200 °C with gas, a successful nanofluid was co-injected with superheated steam at backpressure corresponding to a saturation temperature of 200 °C inside an oven with that set point. Mobility reduction characteristics were obtained for each formulation by normalizing the differential pressure of additive multiphase flow to their respective baselines. Statictests and high-temperature core floods demonstrated a strong synergy between appropriate combinations of surfactants and nanoparticles.None of thesurfactants and nanoparticlesyielded mobility reduction when used on their own; however, when selected according to a design basis, nanoparticle/surfactant mixtures exhibit strong mobility control with steam as well as hot gas. The foam produced in the porous media was held in a visual cellat 150 °C for 24 h with no loss in foam height. Furthermore, foam generated with the nanoparticle-surfactant hybrid remained stable in static tests in the presence of heavy crude oil for more than one week. The primary novelty of this study is the ability to use less exotic surfactants and nanoparticles as steam mobility control agents, increased foam stability in the presence of oil, and demonstrable synergy between commodity molecules (i.e., surfactant) and nanoparticles at steam flooding conditions. The successful additive mixture was developed with scalability in mind such that manufacturing will not hinder the feasibility of scale-up for industrial use.

A paper presents results of an industrial application of an innovative technology for oil and gas producing wells stimulation. Also, research results of a laboratory study of ESN (emulsion system with supercharged nanoparticles) physical and chemical properties under atmospheric and modeled reservoir conditions are briefly described in this paper. The technology is based on the use of an innovative emulsion system with supercharged nanoparticles (ESN) as a solution to solve two tasks at once: 1. to divert an active composition injected after; 2. to block water bearing most-permeable zones within a profile of productive interval for more than 12 months. The case studies considered in this paper focused on the technology application in two mature carbonate formations of Ural-Volga oil-gas province located in Russia. The formations have been under industrial development for almost 50 years and characterized by complicated geology and deteriorated reserves. A combination of effects of diverter and water-blocking agent, in one composition, provides significant competitive advantages, which resulted in two times increase in oil rates with a decrease in water cut of treated by the technology oil-gas producing wells. A duration of positive effect reached 14 months on average for ten treated wells, which is four times higher than a classical acidizing technology applied on the same formations. The main competitive advantages of the technology are enlarged surface charge (alteration of wettability of rock), high thermal stability (150 °C), predictable rheology (Herschel-Balkly model), reversible blocking effect and absence of negative impact on geological formation, downhole equipment and oil and gas collecting system (environmental friendly).

In acid fracturing treatments, the goal is to create enough fracture roughness through differential acid etching on fracture walls such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the closure stress. The viscous fingering phenomenon has been utilized in acid fracturing treatments to enhance the differential acid etching. For relatively homogeneous carbonate reservoirs, by injecting a low-viscosity acid into a high-viscosity pad fluid during acid fracturing, the acid tends to form viscous fingers and etch fracture surfaces non-uniformly. In order to accurately predict the acid- fracture conductivity, a detailed description of the rough acid-fracture surfaces is required. In this paper, we developed a 3D acid transport model to compute the geometry of acid fracture for acid fracturing treatments with viscous fingering. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. Our simulation results reproduced the acid viscous fingering phenomenon ob-served from experiments in the literature. During the process of acid viscous fingering, high-conductivity channels developed in the fingering regions. We performed parametric studies to investigate the effects of pad fluid viscosities and acid injection rates on acid fracture conductivity. We found that a higher viscosity pad fluid and a higher acid injection rate help acid to penetrate deeper in the fracture and result in a longer etched channel.