This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199149, “Rate-Transient-Analysis-Assisted History Matching With a Combined Hydraulic Fracturing and Reservoir Simulator,” by Garrett Fowler, SPE, and Mark McClure, SPE, ResFrac, and Jeff Allen, Recoil Resources, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, originally scheduled to be held in Bogota, Colombia, 17–19 March. The paper has not been peer reviewed. This paper presents a step-by-step work flow to facilitate history matching numerical simulation models of hydraulically fractured shale wells. Sensitivity analysis simulations are performed with a coupled hydraulic fracturing, geomechanics, and reservoir simulator. The results are used to develop what the authors term “motifs” that inform the history-matching process. Using intuition from these simulations, history matching can be expedited by changing matrix permeability, fracture conductivity, matrix-pressure-dependent permeability, boundary effects, and relative permeability. Introduction This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199149, “Rate-Transient-Analysis-Assisted History Matching With a Combined Hydraulic Fracturing and Reservoir Simulator,” by Garrett Fowler, SPE, and Mark McClure, SPE, ResFrac, and Jeff Allen, Recoil Resources, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, originally scheduled to be held in Bogota, Colombia, 17-19 March. The paper has not been peer reviewed. This paper presents a step-by-step work flow to facilitate history matching numerical simulation models of hydraulically fractured shale wells. Sensitivity analysis simulations are performed with a coupled hydraulic fracturing, geomechanics, and reservoir simulator. The results are used to develop what the authors term “motifs” that inform the history-matching process. Using intuition from these simulations, history matching can be expedited by changing matrix permeability, fracture conductivity, matrix-pressure-dependent permeability, boundary effects, and relative permeability. Introduction The concept of rate transient analysis (RTA) involves the use of rate and pressure trends of producing wells to estimate properties such as permeability and fracture surface area. While very useful, RTA is an analytical technique and has commensurate limitations. In the complete paper, different RTA motifs are generated using a simulator. Insights from these motif simulations are used to modify simulation parameters to expediate and inform the history- matching process. The simulation history-matching work flow presented includes the following steps: 1 - Set up a simulation model with geologic properties, wellbore and completion designs, and fracturing and production schedules 2 - Run an initial model 3 - Tune the fracture geometries (height and length) to heuristic data: microseismic, frac-hit data, distributed acoustic sensing, or other diagnostics 4 - Match instantaneous shut-in pressure (ISIP) and wellhead pressure (WHP) during injection 5 - Make RTA plots of the real and simulated production data 6 - Use the motifs presented in the paper to identify possible production mechanisms in the real data 7 - Adjust history-matching parameters in the simulation model based on the intuition gained from RTA of the real data 8 -Iterate Steps 5 through 7 to obtain a match in RTA trends 9 - Modify relative permeabilities as necessary to obtain correct oil, water, and gas proportions In this study, the authors used a commercial simulator that fully integrates hydraulic fracturing, wellbore, and reservoir simulation into a single modeling code. Matching Fracturing Data The complete paper focuses on matching production data, assisted by RTA, not specifically on the matching of fracturing data such as injection pressure and fracture geometry (Steps 3 and 4). Nevertheless, for completeness, these steps are very briefly summarized in this section. Effective fracture toughness is the most-important factor in determining fracture length. Field diagnostics suggest considerable variability in effective fracture toughness and fracture length. Typical half-lengths are between 500 and 2,000 ft. Laboratory-derived values of fracture toughness yield longer fractures (propagation of 2,000 ft or more from the wellbore). Significantly larger values of fracture toughness are needed to explain the shorter fracture length and higher net pressure values that are often observed. The authors use a scale- dependent fracture-toughness parameter to increase toughness as the fracture grows. This allows the simulator to match injection pressure data while simultaneously limiting fracture length. This scale-dependent toughness scaling parameter is the most-important parameter in determining fracture size.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199268, “Upscaling Laboratory Formation Damage Laboratory Test Data,” by Michael Byrne, SPE, Lesmana Djayapertapa, and Ken Watson, SPE, Lloyd’s Register, et al., prepared for the 2020 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, 19-21 February. The paper has not been peer reviewed. Through several case histories, the complete paper demonstrates applications of computational fluid dynamics (CFD) modeling to upscaling of laboratory-measured formation damage and reveals implications for well and completion design. The value of laboratory testing is quantified and interesting challenges to conventional wisdom are highlighted. Introduction Laboratory formation damage testing is often used to help select optimal drilling and completion fluids. Test procedures such as sand retention and return permeability represent an attempt to simulate near-wellbore conditions during well construction and production. To determine what degree of permeability impairment is allowable, further interpretation that cannot be provided using classical nodal analysis or reservoir simulation methods is required. The complete paper describes the evolution of, and potential for, more-comprehensive upscaling and outlines the importance of consideration of full well geometry when designing and interpreting coreflood tests for formation damage. CFD simulations provide a means to upscale suitable laboratory test data to predict effect on well performance. Methods CFD simulations use a relatively simple, steady-state, static damage model that takes endpoint data from laboratory core tests and translates the data into parameters that are used for input into well geometry. Although this method has its merits and is a considerable advance on previous, more-simplistic upscaling attempts, it does not necessarily present the full picture of damage evolution in the near-wellbore. A transient model of damage with data again derived from laboratory coreflood data could reveal more about well cleanup and progressive damage removal. Steady-State Modeling. No API recommended practice for return permeability testing exists. Laboratories have their own procedures that comply broadly with recommended procedures developed some time ago. Operators and consultants, too, have their own procedures, which they often ask laboratories to follow. Although no recommended practice exists, evaluation of drilling and completion fluids usually involves measurement of a base permeability and remeasurement of a return permeability—or several—after application of the test fluid or fluids. In many cases, the laboratory removes the external mud cake or trims a slice of the end of the plug to measure return permeability without mud cake (Fig. 1).

Despite possessing some of the world’s largest shale-gas resources, China is likely in 2020 to have produced less than half of the 30 Bcm per year in shale gas that the government set as a goal in its latest Five-Year Plan. While such a small volume may make shale production seem inconsequential to China’s overall energy balance, it is clear that when it comes to developing unconventional hydrocarbons, China is playing a long game. With regard to shale alone, a 2013 US Energy Information Administration study noted that China has the world’s second-largest technically recoverable shale-gas resources at an estimated 1,115 Tcf; the US is first with 1,161 Tcf. Even more to the point, China is one of only four countries (including the US, Canada, and Argentina) that produce commercial volumes of both shale gas and of tight oil. But it is the lack of efficient technologies and infrastructure that stand in the way of China besting the US and creating its own “shale revolution.” China’s most attractive reserves occur in remote, mountainous areas where, in some cases, shale resources can lie as deep as 3500 m. In separate papers presented in October during the 2020 SPE Russian Petroleum Technology Conference, the China National Petroleum Company (CNPC) detailed new technologies it is applying to meet some of these challenges. Paper SPE 202066, coauthored by subsidiaries of CNPC, Downhole Service Company and CCDC Petroleum Drilling & Technology Company Ltd., details the application of enhanced-hydraulic- fracturing technology (EHFT) to raise the effective stimulated reservoir volume (SRV) in the Sichuan shale basin. A second paper (SPE 202062), coauthored by CNPC and Halliburton, offers a case study in tight-oil production in Daqing employing an intensive fracture-cluster-completion strategy using a microemulsion flowback technology. The Spice in Sichuan Shale China boasts three shale basins (Sichuan, Tarim, and Yantze), but its principal development focus is in the southwestern province of Sichuan, which holds half of the country’s shale reserves. In developing fields such as Weiyuan, Changning, and Jiaoshiba, producers target the Ordovician Wufeng-Silurian Longmaxi formation. The total proved geological reserves of these three gas fields exceeds 500 Bcm, the authors noted in their paper. To develop infrastructure supporting industrial-scale operations and to introduce and test new technologies to raise shale output, China has established several national pilot demonstration areas. One of those is the Weiyuan national shale demonstration area in south Sichuan, where the authors quote an annual production of 2.5 Bcm. Staged horizontal fracturing is the main technology used at Weiyuan and other Chinese shale fields as producers strive to expand the fracture extension area, increase the reconstruction volume, and improve the productivity of single wells. An analysis of production data from Weiyuan showed, however, that the long-term conductivity of fractures is limited because the length and height of supporting fractures are short. Thus, because of the limited volume of reconstruction, production decreases rapidly and efficiency suffers as pressure declines.

The enhanced-oil-recovery (EOR) literature produced in the past several months was dominated by reservoir modeling and characterization; flood enhancements; machine learning; and, more notably, relative permeability estimation. This last one needs to be under-stood further. Relative permeability characterizes flow in porous media, the understanding and manipulating of which is key to the success of EOR. Our fascination with the topic during the last 75 years, therefore, is understandable. Starting with a seminal paper from W.R. Purcell in 1949, we have more than 12,000 articles in the SPE collection alone on relative permeability estimation, of which more than 400 were published in the last year. Mechanics of motion is also important to mankind, but we do not have literature piling up on Newton’s laws of motion. Is it that we haven’t understood flow in porous media yet, or is it because the subject matter is so complex? The truth, perhaps, lies somewhere in between. Flow in pores that are randomly sized, randomly connected, and have variable chemical makeup is, by nature, complex and mathematically unmanageable. Relative permeability has been our attempt to lend its aggregate behavior some sense of manageability. This has always been done in a fit-for-purpose manner. What is fit for one context, however, may not be so for the others, and this uncertainty continues to churn out theses, antitheses, and syntheses. Expectedly, even more such activity arises with every improvement in computing capabilities, as is once again evident with advances in machine learning—new tools to handle old problems. That is where my first pick is for you, with some additional suggested readings in references that follow. Data analytics does much more than estimate relative permeability, and the second paper abridged here uses it to predict a flood performance. To allow a break from data science, the third paper chosen deals with the important topic of electromagnetics as applied to reservoir characterization and heating. I hope you find these to be useful and interesting reads.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19854, “Modeling and Prediction of Resistivity, Capillary Pressure, and Relative Permeability Using Artificial Neural Network,” by Mustafa Ba alawi, SPE, King Fahd University of Petroleum and Minerals; Salem Gharbi, SPE, Saudi Aramco; and Mohamed Mahmoud, King Fahd University of Petroleum and Minerals, prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13–15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. Capillary pressure and relative permeability are essential measurements that affect multiphase fluid flow in porous media directly. The processes of measuring these parameters, however, are both time-consuming and expensive. Artificial-intelligence methods have achieved promising results in modeling extremely complicated phenomena in the industry. In the complete paper, the authors generate a model by using an artificial-neural-network (ANN) technique to predict both capillary pressure and relative permeability from resistivity. Capillary Pressure and Resistivity Capillary pressure and resistivity are two of the most significant parameters governing fluid flow in oil and gas reservoirs. Capillary pressure, the pressure difference over the interface of two different immiscible fluids, traditionally is measured in the laboratory. The difficulty of its calculation is related to the challenges of maintaining reservoir conditions and the complexity of dealing with low-permeability and strong heterogeneous samples. Moreover, unless the core materials are both available and representative, a restricted number of core plugs will lead to inadequate reservoir description. On the other hand, resistivity can be obtained by either lab-oratory analysis or through typical and routine well-logging tools in real time. Both parameters have similar attributes, given their dependence on wetting-phase saturation. Despite many studies in the literature that are reviewed in the complete paper, improvement of capillary pressure and resistivity modeling remains an open research area. Artificial Intelligence in Petroleum Engineering In addition to labor and expense concerns, conventional methods to measure resistivity, capillary pressure, and relative permeability depend primarily, with the exception of resistivity from well logs, on the availability of core samples of the desired reservoir. The literature provides several attempts to model these parameters in order to avoid many of the requirements of measurement. However, the performance of many of these models is restricted by assumptions and constraints that require further processing. For example, the accuracy of prediction of capillary pressure from resistivity is highly dependent on the tested core permeability, which requires measuring it as well to achieve the full potentiality of the model.

By turning up the temperatures downhole, you need less of every-thing up on the surface. This is what is hoped to be proven soon with an experimental chemical technology that is seeing some of its first field tests in Saudi Arabia’s emerging tight-gas formations this year. The innovation centers around reactive chemicals known as thermochemicals that researchers at Saudi Aramco and King Fahd University of Petroleum & Minerals (KFUPM) in Dhahran spent most of the past decade developing. When it comes to unconventional applications, the world’s largest upstream company has two big ambitions. First, it is introducing a new hydraulic fracturing fluid that shaves millions of dollars off the cost of horizontal wells by more than halving the amount of equipment and water typically needed to stimulate the wells. Second, it aims to reduce the number of unproductive fracture stages and the required number of stages by improving stage productivity. “It’s like a hybridization of pulse fracturing and hydraulic fracturing,” explained Ayman Al-Nakhli, a chemist and petroleum scientist at Saudi Aramco’s EXPEC Advanced Research Center. “The thermochemical will create a pressure pulse downhole to break down the rock - then we can propagate the fracture with hydraulic fluids.” Al-Nakhli recently shared new details about the technology at the virtual 2020 Unconventional Resources Technology Conference (URTeC) while presenting a technical paper (URTeC 2439) that he authored with colleagues and university collaborators. The paper outlines laboratory tests in which samples of shale rock from the US and elsewhere were fractured using traditional slickwater fluids alongside the thermochemical approach - or what Al-Nakhli calls the “ExoFrac.” While validation awaits, the years-long research and development project is a reminder that as Saudi Aramco seeks to develop the Kingdom’s tight-gas resources it is not relying solely on the North American experience or its suite of established technologies. The tests highlighted during the conference showed that when pumped into core and other rock samples at the initiation of small-scale hydraulic fracturing treatments, the chemical agents undergo an exothermic reaction that creates a pressure pulse strong enough to induce a fracture in the rock. Meanwhile, as the chemicals reach temperatures that may exceed 270°F, nitrogen gas is rapidly generated inside the fracture which increases its in-situ pressure. As it is drawn up for a real-world application, pumping the thermochemicals downhole would take roughly 5 minutes. Once the reaction is activated, the pressure pulse lasts only milliseconds. The high-temperature reaction continues for no more than 10 minutes before all the heat is absorbed into the surrounding formation.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IPTC 20260, “Stress Sensitivity of Fractured Tight Reservoirs,” by Gang Han, SPE, Aramco, and Kirk Bartko, SPE, Consultant, prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. Wells in unconventional reservoirs can experience sharp rate declines in the early stage of production, especially when experiencing aggressive drawdown. One key factor affecting rate decline is rock sensitivity to increasing compressive stress. The complete paper describes and quantifies the stress-dependence of compaction and permeability for anisotropic rock matrices, natural fractures, and hydraulic fractures, based on comprehensive rock tests of a fractured tight reservoir. Stress Sensitivity and Drawdown Laboratory data show that rock permeability can be reduced by 10 to 99% with increasing confining stress. Controlling factors include rock characteristics such as authigenic cementation, pore structure, clay content, natural fractures, and pore volume compressibility. Additional factors include pore throat size and shape. Low-permeability rocks are more sensitive to stress changes than are high-permeability rocks. A direct link exists between stress-dependent permeability reduction and production decline, especially in unconventional reservoirs in which production declines rapidly during the first year. As production starts and bottomhole pressure is lowered, the effective stress on the rock near the wellbore, defined as the difference between total stresses and pore pressure, increases. Higher loading stress reduces the permeabilities (or conductivities) of induced fractures, natural fractures (or laminations), and the matrix. The increase in effective stress can lead to proppant embedment and crushing, formation spalling, fines migration, rock compaction, and closing of natural fractures. Many of these processes are irreversible and lead not only to rapid production decline but also to reduction of estimated ultimate recovery (EUR). In 2011, analysis of a shale consortia database found that wells with restricted rate (limited drawdown) have 2 to 3 bcf higher EUR than wells with open rate (unlimited drawdown). The analysis also observed that the decline of stress-dependent permeability in propped fractures (millidarcy) is not as severe as the reduction in unpropped fractures (microdarcy) and matrix (nanodarcy).

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 198995, “Low-Salinity Water-Injection Optimization in the Namorado Field Using Compositional Simulation and Artificial Intelligence,” by Diana Mercado Sierra, SPE, Argenis Alvarez Rojas, and Victor Salazar Araque, Computer Modelling Group, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, 27-31 July, Virtual. This paper has not been peer reviewed. The complete paper discusses optimization of a development plan involving low-salinity water injection (LSWI). This methodology combines compositional simulation and a mathematical optimization tool that uses artificial intelligence to maximize the net present value (NPV) of the project under evaluation. The adapted methodology allowed an optimal development plan, considering the uncertainty associated in the reservoir, by use of multiple geostatistical realizations and simultaneous history-matched models. LSWI LSWI is an enhanced-oil-recovery technique in which the salinity of the injected water is controlled with the objective of increasing the recovery factor. Of the mechanisms proposed for LSWI, wettability alteration is the most widely accepted for describing the increase of the recovery factor. The wettability change in reservoirs with the presence of sand-stones mainly is attributed to the multionic exchange between the injected fluid and the clay surface, as is the double layer expansion. From a technical point of view, the LSWI success is related strongly to reservoir lithology. An integrated analysis and optimization study was performed using numerical simulation to evaluate LSWI as an alternative for increasing the recovery factor in the Namorado field in the Campos Basin of Brazil.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30525, “Toward a Recovery Ambition of More Than 70% for the Johan Sverdrup Field,” by Eli Eikje, SPE, Tone Nedrelid, and Elisabeth Bratli, Equinor, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Before the giant Johan Sverdrup barrel of oil, operator Equinor and its license partners set a recovery ambition of greater than 70% for the field. The complete paper discusses key elements driving this ambition. These include the field size and reservoir characteristics, early assessments and investments for improved oil recovery (IOR), data acquisition, reservoir monitoring, and digitalization. Introduction With a recoverable volume range of 2.2-3.2 billion BOE, Johan Sverdrup is a giant oil field approximately 150 km west of Stavanger, the third-largest oil field on the Norwegian Continental Shelf (NCS). The reservoir features hydrostatic pressure and undersaturated oil with a low gas/oil ratio (GOR). The first phase of the field came on stream in October 2019. A predrilling campaign included eight oil producers and 12 injectors. The field is being developed in two phases. Phase 1 includes four bridge-linked platforms: Living quarters with utility-system functions Process platform Drilling platform Riser platform (RP) with tie-in of onshore power Three injection templates are tied back to the RP. All platforms have jacket substructures. Main power to the field is from shore. The full field development includes 64 platform and subsea wells. Phase 2 of the development was approved in 2019 and is expected to start production in Q4 2022. It includes development of another processing platform, modifications of the RP and the field center, five subsea production and injection templates, and power-from-shore supply. The central area with highest hydrocarbon thickness and the highest relief to the free water level was chosen for the field-center location.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199164, “Applied Learnings in Reservoir Simulation of Unconventional Plays,” by Raphael Altman, SPE, Roberto Tineo, SPE, and Anup Viswanathan, SPE, Schlumberger, et al., prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, Bogota, Colombia, 17-19 March. The paper has not been peer reviewed. Reservoir simulation is valuable in understanding dynamics of unconventional reservoirs. Applications include estimating long-term production behavior, enhancing well-spacing and pad-modeling efficiency, optimizing completion and stimulation of horizontal wells, and understanding production drivers that cause differences in productivity between wells. In the complete paper, the authors revisit fundamental concepts of reservoir simulation in unconventional reservoirs and summarize several examples that form part of an archive of lessons learned. Reservoir Simulation Applications in Unconventionals Reservoir simulation plays an important role in many stages of unconventional reservoir field development. In the initial pilot phase, a calibrated reservoir simulation model can provide an indication of estimated ultimate recovery (EUR), which is advantageous given few wells with short production time. EUR evaluation with incorporated uncertainties is a key variable in asset evaluation and investment decisions. During the ramp and development phases, reservoir simulation aids completion optimization by providing a link between completion parameters, such as cluster spacing and stimulation pumping parameters, and a well’s production. Extending this idea further, the integrated nature of reservoir simulation enables identification of production drivers and understanding of why wells are producing differently. During the mature stages of unconventional reservoir development, well spacing and hydraulic fracture and pressure interference, together with refracturing, require advanced modeling techniques that can include a combination of hydraulic fracture simulation, 3D stress simulations, and advanced reservoir simulation. Reservoir Simulation Modeling in Unconventionals Unconventional reservoirs are heterogeneous across multiple scales and exhibit variations in production performance across wells. The production variation is influenced by a large variation in production drivers that simultaneously affect the production. Examples of these drivers include reservoir properties such as hydrocarbon-filled porosity, moveable hydrocarbons, matrix permeability, relative permeability and pressure/volume/temperature, completion properties such as stress-state and natural fractures, and stimulation (pumping) parameters. Reservoir simulation constitutes one of the best tools to understand the dominant production drivers because of the multidisciplinary data required to build simulation models for unconventional reservoirs. Because of the orders of magnitude of difference in matrix permeability between conventional and unconventional reservoirs, pressure gradients from the sandface to the formation (pressure drawdowns) are larger in unconventional reservoirs and drainage radii are more likely to be smaller. Therefore, in the case of shale reservoirs, single-well models usually suffice except for the case of multiwell pads. Very fine grid cells (on the order of inches to a few feet) are used close to, and immediately surrounding, the perforation clusters, whereas in conventional reservoirs, coarser grid cells are used, especially in full-field models, even with local grid refinements.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196281, “Acidizing Done Right in Hot Offshore Wells: Case Study,” by Max Nikolaev, SPE, Bulat Kamaletdinov, and Nestor Molero, SPE, Schlumberger, et al., prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29-31 October. The paper has not been peer reviewed. The complete paper discusses a method of stimulating deep, high-temperature offshore wells by combining an efficient single-phase retarded acid (SPRA) system and an engineered, degradable, large-sized particulate and fiber-laden diverter (LPFD). The method was introduced in a well in the Arabian Gulf, where it helped the operator achieve effective, uniform stimulation. Introduction Treatment of deep, high-temperature carbonate reservoirs such as those in the Arabian Gulf presents a series of complex and related challenges to achieve effective and uniform stimulation. Elevated temperatures and heterogeneous formations in these reservoirs require robust treatment fluids that can withstand the harsh environment to achieve good reservoir contact with an acid system along the entire interval of interest. Emulsified acids have been the preferred stimulation choice of major operators in this region because of these acids’ superior corrosion inhibition and deeper penetration into the reservoir. However, using emulsified acid adds to the complexity of the stimulation operation by contributing to higher friction pressures, limiting pump rates, and requiring elaborate mixing procedures that constrain offshore rig-based interventions. Operators are searching for simplified acid systems that can deliver friction pressure similar to that of unmodified hydrochloric acid (HCl) and reservoir contact performance equivalent to that of emulsified acid. Arabian Gulf operators also seek a robust diverter that can withstand high differential pressure at high temperature, enabling efficient treatment coverage of all perforated intervals. Previous stimulation jobs in the region indicated a need for a significant amount of traditional diversion materials to effectively plug the leakoff zones. To address the challenges, an SPRA and a new degradable LPFD system were introduced to conduct a matrix-stimulation treatment featuring efficient contact with the reservoir, safe corrosion inhibition, and effective diversion in a well with a 320°F bottomhole static temperature and a heterogeneous environment with a permeability contrast of more than 100. The SPRA was a 15% HCl-based acid system. The fluid delivered friction pressures similar to those of unmodified 15% HCl and wormholing performance equivalent to that of emulsified acid without encountering the issues of fluid quality with respect to emulsion stability, and much higher dissolution power than organic acids and chelating agents. The pressure drop after the first acid stage was greater than 1,000 psi in approximately 60 minutes. After the second stage of acid, the pressure drop was close to 1,000 psi in approximately 30 minutes, achieving an approximately 1,000-psi increase of injection pressure across the perforations. Additionally, using the LPFD system reduced the footprint in offshore operations, simplified materials handling, and delivered the most efficient diversion performance in bullhead operations compared with that of other diverters.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19333, “Integrated Detection of Water Production in a Highly Heterogeneous and Tight Formation Using a CRM Model: A Case Study on Waterflooding Gaither Draw Unit, Wyoming, USA,” by Kailei Liu, China University of Geosciences; Xingru Wu, SPE, University of Oklahoma; and Kegang Ling, University of North Dakota, prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. The Gaither Draw unit is a heterogeneous tight formation with an average permeability of less than 0.1 md. After substantial water injection, there was no clear benefit of injected water for any producer. However, knowing the distribution of the injected water is critical for future well planning and quantification of injection efficiency. The objective of this study is to show how the capacitance-resistance model (CRM) was used on this field and how it validated the use of other independent methods. This paper demonstrates that integration of different sources of data in reservoir management is critical. Introduction Unlike numerical reservoir simulation, the CRM requires only the injection rates of each injector and the production rates of each producer as input to evaluate reservoir performance. The connectivity and the time constant that are estimated by fitting production rates can provide useful information about geological features and reservoir heterogeneity. With a clear understanding of reservoir heterogeneity, flow barriers and high-permeability zones can be identified. Significant reservoir heterogeneity may lead to poor sweep efficiency. These characteristic features make the CRM (the development of which is outlined in the complete paper) a unique and practical tool to investigate water-flooding projects. Basics of the CRM The root of the CRM is the governing material-balance equation stating that the mass difference in an arbitrary control volume (CV) is equal to the mass difference between injected and produced fluid passing through this CV. Then, the governing material-balance equation is combined with a linear productivity model to obtain an ordinary differential equation. The semianalytical solution of the ordinary differential equation forms the CRM. In the field case, there are often many injectors and producers, which would be a large nonlinear optimization problem in the CRM. A CRM-producer (CRMP) model can be used to reduce the number of time constants and increase computational speed. The equations contributing to such a model are provided in the complete paper. Case Study The study area is located in the Parkman reservoir, which is a part of the Powder River Basin in southeast Montana and northeast Wyoming. The Parkman Sandstone Member of the Upper Creta-ceous Mesaverde formation is the oldest sandstone member in a widespread cycle of late Cretaceous regression. The Parkman reservoir consists of multiple stacked sands 5,000 to 9,500 ft deep. There are three dominant lithologies of the Parkman reservoir. The first is pro-delta shale and siltstone, which includes very fine and well-sorted sandstone. The second is medium-grained sandstone, which lies as coarsening-upward successions mixed with siltstone. The last is silt and mudstone, which gradually changes from exhibiting carbonaceous to lignitic characteristics.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 196217, “Assessment of Government Incentives and Development Strategies To Revitalize Mature Heavy-Oil Fields in the Peruvian Jungle,” by Nosser A. Jurado, SPE, National Bank Financial, and Victor A. Huerta, SPE, Universidad Nacional de IngenerÍ​​​​​​​a, prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September–2 October. The paper has not been peer reviewed. Mature heavy-oil fields in the northern Peruvian jungle have produced oil for more than 40 years under primary recovery mechanisms (cold methods). The complete paper explores technical and economic development options to produce heavy-oil resources at commercial rates and showcases three optimization scenarios of higher recovery efficiency aimed at increasing net present value at the basin level. Introduction The constant decline of medium- and light-oil production in most Peruvian fields in recent years, along with the increase in domestic demand, indicates that innovative redevelopment strategies should be implemented for recent large heavy-oil discoveries in the Marañon Basin. The Norperuano pipeline in its current condition and egress capacity allows exploitation of proved developed producing volumes of Blocks 64, 192, 8, and 95 but constrains the commerciality and development possibilities for Block 67 (Piraña, Dorado, and Paiche fields) and Block 64 (Situche field), which jointly could pro-duce up to 70,000 B/D between 2027 and 2029. The main issue is the present constraint for transportation and blending of heavy oil and diluents. Therefore, an infrastructure revamp is necessary. The authors believe that capital expenditure (CAPEX) to carry out these improvements and expansions is necessary and must be addressed between the operators in the area and the Peruvian government while considering all social and current environmental issues. Analysis of Production Performance and Recovery Most Peruvian heavy-oil fields have been discovered in the Marañon Basin. Production history indicates a strong water-drive mechanism by which oil production declines as water rate increases, while reservoir pressure is sustained with a less than 20% pressure decrease. Generally speaking, Marañon wells have been drilled following slant trajectories and are only completed with slotted liners without a selective completion. Consequently, no method exists to isolate water zones or encroachment, and oil productivity and relative permeability to oil decrease rapidly as water cut increases. Horizontal wells have been proposed for the Bretaña heavy-oil field in Block 95. This field is similar to the Jibaro and Jibarito fields in Block 192, with completions featuring autonomous inflow-control devices (AICDs) to delay water breakthrough while improving production performance and increasing oil recovery. Another alternative suggested to increase recovery factor and prevent water breakthrough is dual completion with electrical submersible pumps (ESPs). This completion type has been envisioned for Block 192. On a well-by-well basis, increasing the recovery factor by implementing new technologies is possible. On a transportation-and-gathering basis, however, issues remain in the basin. A production deferment of at least 7% has been the result of several factors, including a lack of appropriate well-service programs to replace ESPs and clean boreholes, inadequate infrastructure, deteriorating roads accessing the fields, the lack of a supply-change-management program, and a lack of appropriate management of social and environmental issues. CAPEX allocations to the Norperuano pipeline would minimize this problem at the basin level and might solve delay issues at the field level for all blocks.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 191670, “Wastewater Injection and Slip Triggering: Results From a 3D Coupled Reservoir/Rate-and-State Model,” by Mohsen Babazadeh, SPE, and Jon•Olson, SPE, The University of Texas at Austin, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer•reviewed. This paper presents a coupled 3D fluid-flow and geomechanics simulator developed to model induced seismicity resulting from wastewater injection. The simulator modeled several cases of induced earthquakes with the hope of providing a better understanding of such earthquakes and their dominant causal factors, along with primary mitigation controls. Implementation of rate-and-state friction to model friction weakening and strengthening during fault slip to accurately model earthquake occurrence, and an embedded discrete fracture model to efficiently model fluid flow inside the fault, are among the essential features of the simulator. The complete paper presents results from a combined model that brings together injection physics, reservoir dynamics, and fault physics to explain better the primary controls on induced seismicity. Introduction Since 2009, a substantial increase in the number of earthquakes in the central and eastern United States has occurred. Oklahoma has been one of the most affected regions, with several earthquakes of M•5+, including the Prague earthquake in 2011 and the Pawnee earthquake in 2016. This has prompted efforts to find and understand any correlation between oil and gas activity—mainly wastewater disposal—and the occurrence of the earthquakes. Induced or triggered seismicity associated with wastewater injection, mining, oil and gas extraction, and geothermal operations has been identified since the earthquakes at the Rocky Mountain Arsenal in 1960s. Fluid injection into subsurface formations can increase pore pressure, reduce the effective stress, and induce slip on faults. Laboratory studies show that the sliding displacement may enhance fracture transmissivity and create a hydraulic pathway through the formation. In an unconventional reservoir, the enhancement could lead to improved hydrocarbon production by using the slipped natural fractures. But in some formations, such as water-disposal aquifers, seismicity might be induced when faults are activated within the igneous basement. Seismicity induced by fluid injection is controlled by several groups of parameters (injection, reservoir, and frictional). A fundamental understanding of which factors are the most important in triggering slip in areas of active wastewater injection and disposal has been hampered by interrelationships between the various parameters, leading to suggestions of injection volume, rate, or pressure being the most important. However, necessary reservoir characteristics, such as size and permeability, are not well characterized at the well or in the subsurface, and remain the main challenge for deterministic models. Additionally, rupture nucleation on faults near a region of injection depends on rate-and-state and related physics. The literature contains many relevant seismicity studies, which are identified in the reference section of the complete paper. A 2D simulation of fluid flow inside the fault zone suggested that post-shut-in earthquakes are likely to occur nucleating at the fault edges. Using a similar numerical scheme, other researchers investigated the 2011 Prague earthquake sequence to model the delayed triggering mechanism between the M 4.8 fore-shock and M 5.6 main shock. The result of the study contributed to defining constraints on values of fault transmissivity, fault compliance, and rate-and-state frictional properties. Although expensive, these types of full-physics models are capable of characterizing reservoir and fault properties. A 3D simulation in 2015 modeled fault activation under direct injection into the fault during shale-gas hydraulic fracturing. It found that for brittle faults, the moment magnitude can be higher.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IPTC 19378, “Comprehensive Evaluation of NMR Characteristics of Complex Volcanic Reservoirs With Different Types of Rock Lithology,” by Junchang Sun, Shijie Zhang, Jieming Wang, Hekun Guo, Chun Li, Hongcheng Xu, Sinan Zhu, and Kai Zhao, PetroChina, prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. This paper discusses a study undertaken to gain better understanding of nuclear magnetic resonance (NMR) characteristics of volcanic reservoirs with different lithologies. Results of the study confirmed that accurate identification of reservoir-interval lithology, achieved through comprehensive laboratory NMR investigation of the volcanic rock, is a primary prerequisite of correct interpretation of NMR logging of volcanic reservoirs. The research results play an important role in guiding in-depth understanding of NMR characteristics of volcanic reservoirs and the implementation of NMR reservoir evaluation in corresponding areas. Introduction The introduction of NMR to the petroleum industry in the 1990s led to a breakthrough in logging. NMR can distinguish between movable and irreducible fluid, and is currently the only logging technology that can determine reservoir permeability. When used to interpret and evaluate complex reservoirs such as volcanic rocks and low-resistivity oil and gas layers, NMR provides logging analysts with new ideas and techniques to deal with various difficulties. By analyzing the NMR relaxation-time ( T 2 ) spectrum of rock plugs at a fully brine-saturated state, the distribution of reservoir pore size can be evaluated, and important reservoir evaluation parameters, including effective porosity, NMR permeability, and movable fluid saturation, can be obtained. Numerous studies have shown that, compared with sandstones and carbonates, volcanic reservoirs are much more complex and heterogeneous because of the special eruption diagenesis mechanism, many types of rock lithology, various mineral compositions, and a broad range of pore sizes. The models currently used for NMR logging interpretation are suitable only for sedimentary reservoirs. Consequently, accurate characterization of volcanic reservoirs using advanced NMR logging requires a comprehensive laboratory NMR investigation of volcanic rock. Materials and Methods For the study described in the complete paper, NMR sample analysis technology was adopted to perform NMR measurements and other related tests on a total of 108 low-permeability rock plugs from the Xushen reservoir of the Daqing field, the Changling reservoir of the Jilin field, and the Dixi reservoir of the Xinjiang volcanic gas field. The rock plugs comprised nine types of lithology representing the main producing formation lithology from the three reservoirs. Tests included CT scans, thin-section petrography, mercury injection, and mineral-composition analysis. Centrifuge tests were conducted with maximum centrifugal forces up to 500 psi to explore the suitable capillary pressure for T 2 cutoff determination. The paper includes a step-by-step description of the experimental procedure.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190852, “Open-Source Tool Kit for Micromodel Generation Using 3D Printing,” by Thomas D. Seers and Nayef Alyafei, SPE, Texas A&M University at Qatar, prepared for the 2018 SPE Europec featured at the 80th EAGE Conference and Exhibition, Copenhagen, Denmark, 11–14 June. The paper has not been peer reviewed. In this paper, the authors present an open-source tool kit for the generation of microfabricated transparent models of porous media (micromodels) from image data sets using optically transparent 3D polymer additive manufacturing (3D printing or sintering). These micromodels serve as research and pedagogical tools that facilitate the direct visualization of drainage and imbibition within quasi-2D porous media, generated from a range of image modalities [e.g., thin section micrographs, µ-computed tomography (µCT) orthoslices, and conventional digital photography]. Introduction Though recent advances in 3D X-ray imaging, such as X-ray microtomography and µCT, permit volumetric imaging of microcore flood experiments with-in geological samples at the pore scale, experimental observations of dynamic (time-resolved) multiphase flow with-in pore networks still are obtained conventionally using transparent etched or molded synthetic porous media commonly referred to as micromodels. Typically, video footage of fluid imbibition and drainage experiments conducted across these quasi-2D pore networks is used to understand fluid distributions and displacement mechanisms within an equivalent 3D porous media. Contrary to state-of-the-art dynamic µCT coreflood experiments, which require synchrotron beam time to be conducted, micromodel studies can be undertaken routinely within a laboratory-based setting with a relatively simple experimental setup. However, the facilities required to fabricate micromodels typically are highly specialized, with production often outsourced to third-party manufacturers. In this work, the authors consider the potential of using additive manufacturing (3D printing or sintering) as an alternative to conventional micromodel-fabrication techniques. With the advent of light-transmissible 3D-printable materials, flow experiments conducted with these 3D-printed physical models can be captured using widely available optical imaging techniques (i.e., standalone digital cameras and trinocular microscopes). However, a major obstacle encountered in harnessing 3D-printing technologies for the goal of micromodels fabrication is the paucity in software tools capable of processing and converting raster-based images to mesh-based file formats parsable by commercially available 3D-printing systems. The paper aims to provide an open-source platform through which 3D-printable mesh-based representations of micromodels can be generated from raster imagery. Using this tool, standard micromodel components are fully integrated into the fabricated model. The availability of such a tool kit could act as an enabler for community research into fluid-transport phenomena in porous media. The authors suggest that 3D-printed pore networks may provide an effective pedagogical tool for teaching multiphase flow, enabling petroleum- and chemical-engineering and geology students to visualize directly often obtuse immiscible-fluid-flow processes within the classroom. Software-Implementation Description The tool kit is developed in the popular MATLAB language and is executed by graphical user interface. The generation of 3D-printable micromodels from raster datasets comprises three main stages: Image processing Micromodel construction Mesh post-processing

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190277, “Mechanistic Study for the Applicability of CO2-EOR in Unconventional Liquids-Rich Reservoirs,” by Dheiaa Alfarge, SPE, Iraqi Ministry of Oil and Missouri University of Science and Technology, and Mingzhen Wei and Baojun Bai, Missouri University of Science and Technology, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. Improved oil recovery (IOR) methods for shale-oil reservoirs are considered relatively new concepts compared with IOR for conventional oil reservoirs. Different IOR methods—including CO 2 , surfactant, natural gas, and water injection—have been investigated for unconventional reservoirs using laboratory experiments, numerical simulation studies, and limited pilot tests. For a variety of reasons, CO 2 injection is the most-investigated option. In this paper, numerical simulation methods of compositional models were incorporated with logarithmically spaced, locally refined, and dual-permeability reservoir models and local grid refinement (LGR) of hydraulic-fracture conditions to investigate the feasibility of CO 2 injection in shale oil reservoirs. Introduction Advancements in horizontal drilling and hydraulic fracturing enabled unconventional liquids-rich reservoirs (ULRs), such as shale and source-rock formations and very tight reservoirs, to change the oil industry. ULRs are characterized by pore throats of micro- to nanomillimeters and an ultralow permeability. Although different studies re-ported that these ULRs contain billions of recoverable oil barrels in place, it is estimated that less than 7% of the original oil in place can be recovered during the primary depletion stage. Production sustainability is the main problem behind the low oil recovery in these unconventional reservoirs. Oil wells in ULRs typically start with a high production rate, but show a steep decline rate in the first 3–5 years of production life because of the rapid depletion in the natural fractures combined with a slow recharge from the rock matrix. The logical steps of academic research such as experimental investigation, simulation studies, and pilot tests for examining the applicability of different unconventional IOR methods have just begun in the past decade. Applying one of the feasible IOR methods in most oil and gas reservoirs should be mandatory to increase the oil-recovery factor. However, the mechanisms of IOR methods in unconventional reservoirs are not necessarily the same as those in conventional reservoirs. The primary characteristics of unconventional reservoirs that might impair performing IOR operations are low porosity and ultralow permeability. As a result, finding IOR methods that are insensitive to these very small pore throats is a priority.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191457, “Coupling Geomechanical Effects and Reservoir Dynamics for Modeling Rejuvenation in Unconventional Plays,” by R. Dutta, SPE, Drilling Info; R. Pinto, Sciences Po University; and J.C. Flores, S.M. Stolyarov, SPE, and J. Yang, Baker Hughes, a GE Company, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed. An integrated understanding of geomechanical effects, fracture propagation, and reservoir dynamics is critical in the efficient and cost-effective application of rejuvenation technologies for unconventional plays. While various reservoir models depicting the hydraulic-fracturing process are available in the industry, many tend to be simplified or do not capture the numerous parameters that affect both the initial and restimulation processes. This work takes a further step toward building a more-realistic picture of fracturing in unconventional plays. Introduction A common assumption in reservoir simulation is that the proppant-fluid mixture is present in the hydraulic fracture before flowback and production. The quantity of water assumed to be present in the hydraulic fractures is a conjecture and is calibrated generally with production-logging tools. These assumptions may skew the results of hydrocarbon recovery. A method of incorporating geomechanical aspects of fracturing into the model involves the concept of pressure-dependent permeability variation in natural fractures that results in formation of pressure-dependent stimulated reservoir volume (SRV). Hysteretic permeability models employed in numerical modeling can offer a description of the SRV and also can be used in addressing longer-term geomechanical effects in a practical manner. While this concept has matured in the context of modeling hydraulic fracturing in reservoir simulation, it is being newly applied in modeling refracturing treatments. Because the importance of capillary effect in low-permeability formations is recognized, the authors also incorporate capillary pressure in their model. In addition to pressure-dependent permeability variation, results explain how capillarity is significant in understanding fluid migration, the trapping of fluid in the matrix, and, consequently, restimulation. Methodology The main challenge in selecting good candidate wells for this study was in finding wells that targeted the same formation, used varying refracturing technologies, and had sufficient data to build a reservoir-simulation model with input for the reservoir properties. After studying a large number of wells, the authors focused on two horizontal gas wells producing from the Barnett Shale. One well was identified to be refractured with a selective zone-treatment method, while the other used a method of fluid diversion. The wells are located approximately 3 miles from each other and approximately 1,600 ft from neighboring wells. These wells have differing production signatures, but this is not indicative of a difference in the performance of two technologies. Understanding the difference in performance may be key to planning a successful refracturing operation.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 191521, “Quantitative Integration of 4D Seismic with Reservoir Simulation,” by Sarath Pavan Ketineni, SPE, Subhash Kalla, SPE, Shauna Oppert, SPE, and Travis Billiter, SPE, Chevron, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Standard history-matching work flows use qualitative 4D seismic observations in reservoir modeling and simulation. However, such work flows lack a robust framework for quantitatively integrating 4D seismic interpretations. Four-dimensional, or time-lapse, seismic interpretations provide valuable interwell saturation and pressure information. Quantitatively integrating these data can help constrain simulation parameters and improve the reliability of production modeling. This paper outlines the value of 4D for reducing uncertainty in the range of history-matched models and improving the production forecast. Introduction Reservoir-simulation models play an essential role in generating optimal field-development strategies, but they need to be history-matched before they can be used for reliable forecasting. Traditional history matching of a reservoir involves matching observed production and pressure data at well locations by changing the uncertain parameters in the reservoir model within the acceptable range. The parameters can be classified broadly as static and dynamic. Static parameters include permeability, porosity, and net to gross, among many others. Dynamic parameters may include oil/water contacts, fault transmissibilities, relative permeability curves, and flow pathways. Deterministic modeling focuses on a single scenario of the reservoir model, ignoring the effect of uncertainty in the parameters considered. Probabilistic history matching is the process of selecting non unique and multiple history-matched reservoir models by altering the uncertain static and dynamic parameters to obtain a range of possible forecasts. Typically, in probabilistic work flows, objective functions composed of a combination of differences in measured and simulated bottomhole pressure data and individual fluid-phase flow rates are used to identify significant factors or uncertainties. The functions are typically based on surveillance data obtained at well locations and therefore may not be sensitive to key reservoir uncertainty away from wells. A good match with production data for a given reservoir model does not ensure robustness in making performance forecasts. Reservoir heterogeneities—high-permeability pathways, barriers and baffles, or vertical connections forged from geologic erosion—can significantly affect drainage and swept patterns and well-production forecasts. Especially during early stages of field production, history matching to pressure and fluid-rate production data often lacks information necessary to resolve these critical heterogeneities fully, which may significantly affect production. Even a well-posed probabilistic history-matching approach cannot incorporate the variety and complexities of heterogeneities that are yet to have a strong imprint on future production because of insufficient data away from wells and the sheer number of static and dynamic uncertainties that can affect production.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189569, “Fines Migration During CO2-Saturated Brine Flow in Carbonate Reservoirs With Some Migratory Clay Minerals—Malaysian Formations,” by Y. Sazali, Petronas; S. Godeke, SPE, Universiti Brunei Darussalam; W.L. Sazali and J.M. Ibrahim, Petronas; G.M. Graham and S.L. Kidd, Scaled Solutions; and H.A. Ohen, SPE, HPO Global Resources Ventures, prepared for the 2018 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 7–9 February. The paper has not been peer reviewed. A high-carbon-dioxide (CO 2 ) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development. Reservoirs in this region have an average clay content of 8%; more than 50% of this clay content is migratory illite, and 15% is migratory kaolinite. Therefore, fines migration exacerbated by this low-permeability rock becomes a potential production and injection problem. A study was conducted involving rock mineralogy and dynamic flow to evaluate factors contributing to potential fines-migration damage within the production and injection interval. Introduction Migration of fines is associated with oil and gas production in sandstones as well as carbonate reservoirs. Fine particles located on the surface of rock grains are affected by adhesion, drag, and electrostatic and gravitational forces. Drag and lifting forces detach the particle, whereas adhesion, electrostatic, and gravitational forces press the particle to the surface. Generally, the main sources of movable fine particles in sandstone reservoirs are kaolinite and illite clays. Kaolinite particles are flat plates usually stacked in the form of booklets. The surface area of clay minerals, for example, typically is large because of their structure and small size and is more reactive and prone to mobilization and migration. Once mobilized, the fine particles are retained by size exclusion if their size exceeds the pore-throat size of the matrix. Fines damage also occurs when several small fine particles reach a larger pore throat at the same time and compete for passage through the throat with the result of bridging and sedimentation. Usually, in the case of gas/water flow, the fines move with the wetting water phase. However, fines movement taking place before water movement has been observed in a number of gas reservoirs. The in-situ mobilization and migration of fines without a mobile wetting phase is primarily caused by hydrodynamic drag that exceeds the critical rate to mobilize the fines. It has long been realized during corefloods that colloidal controlled release of particles leading to fines migration may be caused by salinity change following flow rate that causes the fines to bridge at the pore throat. Generally, a decrease in salinity or an increased rate of salinity change leads to particle mobilization. This decrease in permeability caused by decreasing salt concentration has been found to be nonmonotonic.