bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Well Shut-in After Hydraulic-Fracture Treatments on Productivity and Recovery in Shale Oil Reservoirs
Authors: Eltahan Esmail , Bordeaux Rego Fabio , Yu Wei , Sepehrnoori Kamy 
Published: August 2020

Abstract
Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery.
We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement.
Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geo-mechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition counter-current flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.
Gas EOR Processes in Tight Unconventionals
Authors: Mydland Stian , Yusra Ilina , Whitson Curtis Hays , Dahouk Mohamad Majzoub , Carlsen Mathias Lia 
Published: August 2020

Abstract
The purpose of this paper is to (1) describe the mechanisms of gas-based enhanced oil recovery (EOR) in tight unconventionals, and (2) emphasize the need for single-porosity model tuning of the dual-porosity model when it is used to model EOR for unconventionals on well or field scale. We study two different gas-based EOR methods that inject and produce cyclically through the same well: The Huff-n-Puff (HnP) method, and a method we will refer to as the Fracture-to-Fracture (F2F) in which every other hydraulic fracture is used for injection and production in each cycle. We show that the recovery mechanisms and EOR target volume for HnP and F2F are fundamentally different.
We argue that the target volume for HnP is a rubblized ("shattered") rock volume adjacent to the hydraulic fracture. To accurately predict the performance of this rubblized region, we use a compositional reservoir simulator that includes molecular diffusion to model the EOR performance of rubble-rock pieces of varying size.
Gridding of numerical models is given considerable attention for both HnP and F2F to show its importance when modeling miscible EOR processes. Coarse gridding may result in significant numerical dispersion, which can falsely yield artificially optimistic recoveries for the HnP process.
Results from this paper show that the primary recovery mechanism for HnP stems from a target EOR volume represented by a rubblized rock volume. The size of the rubble, and in particular its minimum dimension, will control the amount of gas that enters, mixes, and recovers oil from the rubble pore space through a process of Darcy flow, molecular diffusion, and phase behavior that involves swelling, vaporization, and first-contact miscibility conditions. The F2F method is not particularly affected by the rubblized region, but instead targets recovery from the entire rock volume between hydraulic fractures; this EOR process is akin to a conventional miscible-displacement mechanism with a much larger EOR target than HnP.
The F2F method is presented in this paper as an alternative to the HnP method to show that HnP is not necessarily the best or the only EOR strategy in tight unconventionals. The EOR target volume for F2F is potentially much larger than for HnP, as everything between the fractures may be swept with a piston-like efficiency. However, the response time (i.e. the time before uplift in production is observed) can be much longer for F2F than HnP, depending mainly on the fracture spacing and matrix permeability.
Comparison of Surfactant-Polymer and Polymer Flooding in a High Temperature Sandstone Reservoir
Authors: Masduki Agus , Syafwan Muhammad , Nursyahid Bambang , Armpriester Andrew , Dean Robert , Dwarakanath Varadarajan , Malik Taimur , Meaux Dwight , Slaughter Will , Thach Sophany 
Published: August 2020

Abstract
Results from two field trials designated as Minas Surfactant Field Trial 2 (SFT2) and Polymer Field Trial (PFT) are presented. Quantitative tracer interpretations were used to estimate sweep and displacement efficiency and confirm the performance of both SFT2 and PFT. The pilot patterns in both SFT2 and PFT consisted of a central producer surrounded by six chemical injectors and further confined by six hydraulic control wells that injected water alone. In order to make quantitative comparisons, both the surfactant-polymer and polymer pilots were run at the same mobility ratios to understand if incremental recovery was a function of improved volumetric sweep or increased displacement sweep efficiency. The results of the two pilots show that at the same well spacing and mobility ratio, incremental sweep is very similar and significantly higher than pre-chemical waterfloods. An important finding of the tracer tests is that water injectors should not be used to confine chemical injectors as the water tends to bypass the higher viscosity polymer chase and potentially disrupts the oil-bank. The results from the pilots indicate that for a mature, waterflooded reservoir, surfactant-polymer flooding was preferable as it lowered the final remaining oil saturation and increased oil recovery. Polymer flooding mainly accelerated oil recovery by recovering additional oil from unswept zones and had minimal impact in a mature reservoir. Interwell tracer technology combined with moment analyses were used to make quantitative comparisons of both processes and allowed for several technical insights. This is the first time in literature that a quantitative comparison of surfactant-polymer flooding and polymer flooding alone has been presented.
Analyzing the Dynamics of Mineral Dissolution During Acid Fracturing by Pore–Scale Modeling of Acid–Rock Interaction
Authors: You Jiahui , Lee Kyung Jae 
Published: August 2020

Abstract
Hydrochloric acid is commonly used in acid fracturing. Given that the interaction between acid and rock affects multiphase flow behaviors, it’s important to thoroughly understand the relevant phenomena. Darcy–Brinkman–Stokes (DBS) method is most effective to describe the matrix–fracture system among the proposed models. The objective of this study is to analyze the impact of acid–rock interaction on multiphase flow behavior, by developing a pore–scale numerical model applying DBS method. The new pore–scale model is developed based on OpenFOAM, which is an open source platform for the prototyping of diverse flow mechanisms. The developed simulation model describes the fully–coupled mass balance equation and the chemical reaction of carbonate acidization in an advection–diffusion regime. Volume of Fluid (VOF) method is employed to track liquid and gas phase interface on fixed Eulerian grids. Here, penalization method is applied to describe the wettability condition on immersed boundaries. To compute the numerical solutions of discretized equations, finite volume method is applied, where the equations of saturation, concentration, and diffusion are solved successively, and momentum equation is solved by using Pressure–Implicit with Splitting of Operators (PISO) method, respectively. The simulation results computed by this numerical model have been validated by experimental results. Different injection velocities and the second Damkohler numbers have been simulated to investigate their effects on the evolving porosity and rock surface area. The newly developed pore–scale model in this research provides the fundamental knowledge of physical–and–chemical phenomena of acid–rock interaction and their impact on acid transport. The modelling results describing mineral aci dization will help us to implement an effective fracturing project while reducing environment impacts.
Instow a Full Field, Multi-Patterned Alkaline-Surfactant-Polymer Flood – Analyses and Comparison of Phases 1 and 2
Authors: Pitts Malcolm J. , Dean Elio , Wyatt Kon , Skeans Elii , Deo Dalbir , Galipeault Angela , Mohagen Dallas , Humphry Colby 
Published: August 2020

Abstract
An Alkaline-Surfactant-Polymer (ASP) project in the Instow field, Upper Shaunavon formation in Saskatchewan Canada was planned in three phases. The first two multi -well pattern phases are nearing completion. Beginning in 2007, an ASP solution was injected into Phase 1. Phase 1 polymer drive injection began in 2011 after injection of 35% pore volume (PV) ASP solution. Coincident with the polymer drive injection into Phase 1, Phase 2 ASP solution injection began. Phase 2 polymer drive began in 2016 after injection of 47% PV ASP solution. Polymer drive continues in both phases with Phase 1 and Phase 2 injected volume being 55% PV and 35% PV, respectively. Phase 1 and Phase 2 oil cut response to ASP injection showed an increase of approximately four times from 3.5% to 12 to 16% and an increase in oil rate from approximately 3,200 m3/m (20,000 bbl/m) to 8,300 m3/m (52,000 bbl/m) in Phase 1 and from 2,200 m3/m (14,000 bbl/m) to 7,800 m3/m (49,000 bbl/m) in Phase 2. Phase 1 pattern analysis indicates the pore volumes of ASP solution injected varied from 13% to 54% PV of ASP with oil recovery percentage increasing with increasing injected volume. Oil recoveries in the different patterns ranged from 3% OOIP up to 21% OOIP with lower oil recoveries correlating with lower volume of ASP injected. The response from some of the patterns correlates with coreflood results. Wells in common to the two phases show increase oil cut and oil rate responses to chemical injection from both Phases 1 and 2. Oil recovery as of August 2019 is 60% OOIP for Phase 1 and 57% OOIP for Phase 2. Phase 1 economic analysis indicated chemical and operation cost would be approximately C$26/bbl resulting in the decision to move forward with Phase 2.
Experimental Investigation of the Effect of Polymer Viscoelasticity on Residual Saturation of Low Viscosity Oils
Authors: Jin Julia , Qi Pengpeng , Mohanty Kishore , Balhoff Matthew 
Published: August 2020

Abstract
We performed coreflood experiments to determine the effect of polymer viscoelasticity on the residual saturation of low viscosity oils by varying the rock type, wettability, polymer rheology, and flow conditions. Several authors have shown that polymers, if viscoelastic, can recover a significant amount of capillary-trapped oil, beyond inelastic floods, in water-wet sandstones. We demonstrate that the polymer viscoelastic effect works for several different rock types, both water-wet and oil-wet media, and with low viscosity oils which broadens the applicability found in previous works. In polymer field studies, the rheology can be tailored to maximize the effect based on our findings.
Eleven corefloods were performed in Bentheimer, Boise, and Berea cores. Two of the cores were made oil-wet using dichlorodiphenylsilane (DCDPS) and chlorotrimethylsilane (CTMS). The cores were initially saturated with brine and then displaced by low viscosity (4-10 cp) crude oil until steady state was reached. Brine was then injected to displace the oil until steady state and residual oil saturation was reached. In most experiments, HPAM polymer was then injected at ∼1 ft/day; the polymer rheology was tailored via the salinity, concentration, molecular weight, and degree of hydrolysis. Once steady state was reached, a second polymer solution (with the same viscosity but higher salinity) was injected until a final oil saturation was reached. A reduction in oil saturation was observed in all corefloods in which the polymer was viscoelastic. On average, the oil saturation was reduced by 5.6% in the first polymer flood and 4.0% in the second, high salinity polymer flood. Higher recoveries were found for some experiments in which the first polymer was more elastic (higher dimensionless Deborah number). Final oil saturations as low as 5% were achieved using only polymer (and no surfactant). Results were not dependent on the rock type (e.g. Bentheimer versus Boise) but the effect was more pronounced in water-wet cores than those changed to oil-wet.
A Comparison Simulation Study of GDWS-AGD EOR Process Performance Using CO2/APG Alternatives in South Rumaila Oil Field, Iraq
Authors: Al-Mudhafar Watheq J , Wojtanowicz Andrew K 
Published: August 2020

Abstract
To date, feasibility studies of the Gas and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) process for the South Rumaila oil field have considered using Carbon Dioxide gas injection to enhance oil recovery. As availibility of CO2 is limited and its cost considerable it might be also feasible to use natural gasAssociated Produced Gas (APG), that has been recently tested as an alternative solvent to enhance oil recovery. The paper reports on a simulated comparison of the APG or CO2 application in the South Rumaila oil field. The comparison metrics include field recovery factor, water cut in oil and water producers, Gas Oil Ratio in oil producers, cumulative gas injection, and average saturation.
In the study, the GDWS-AGD process installation comprises 20 vertical APG injection wells completed at the top of the reservoir to build a gas cap in the oil pay zone. In addition, eleven horizontal oil-producing wells are placed at the bottom of the oil pay zone with six horizontal water drainage (sink) wells below the oil-water contact (OWC). The two horizontal leg installation may be made from a vertical well with 7-casing dual-completed (from two kick-off points) in the oil payzone and in the bottom water (below OWC) with two horizontal well legs and the two 2-3/8 inch tubings in each well. In a dual-tubing design of the process the two horizontal well legs produce independently. If only one tubing is used production from the water sink well is hydraulically isolated inside the vertical well by a packer. In either design, the water sink well is operated with a submersible pump.
In this study, the GDWS-AGD process with APG is considered for the upper sandstone member/South Rumaila Oil Field, located in Iraq to improve oil recovery. The Rumaila field has an infinite acting-aquifer with very strong edge water drive. In the GDWS-AGD, the bottom water drainage would not only reduce water cut and water cresting, but would also significantly reduce the reservoir pressure, resulting in improving gas injectivity by significantly reducing the need for high injection pressure and gas solubility will be also reduced in the immiscible mode. Significant improvement with the GDWS-AGD process - oil recovery increased from 76.5% by CO2 to 82.5% by APG and water cut was readily controlled resulting in more rapid reduction with APG (from 95% to less than 5%) than that with CO2 in all horizontal oil producers. The results show that the use of APG alternative to CO2 for the GDWS-AGD process not only improves water-cresting and controls water cut, but also enhances gas injectivity and significantly improves oil recovery.
Characterization of Carboxylate Surfactant Retention in High Temperature, Hard Brine Sandstone Reservoirs
Authors: Pinnawala Gayani , Davidson Andrew , Taylor Isbell , Yang Hyuntae , Slaughter Will , Kim Do Hoon , Malik Taimur , Dwarakanath Varadarajan 
Published: August 2020

Abstract
Large hydrophobe Carboxylate surfactants (MW above 1000) are a relatively new class of surfactants developed for surfactant flooding during chemical enhanced oil recovery (EOR) processes. The presence of carboxylate groups and alkoxylate groups in the molecules provides stability and salinity tolerance at high temperature and in high salinity environments. Many high temperature reservoirs have injection and reservoir brine containing high concentrations of divalent ions making them prime targets for using carboxylate surfactants. Much of the earlier literature showed successful carboxylate applications at high pH during alkali-enhanced flooding, as the high pH stabilizes the carboxylate groups. Such processes are not feasible in the presence of hardness at high temperatures. We present an approach where we use an alkali buffer wherein the pH is adjusted from highly basic to near neutral. Under such conditions we demonstrated low retention and high performance in terms of phase behavior and coreflood oil recovery.
A Simulation Case Study of Gas Injection Pilot in Eagle Ford
Authors: Rogers J. Brandon , Basbug Basar , Firincioglu Tuba , Ozgen Chet 
Published: August 2020

Abstract
This paper focuses on simulation modeling of a gas injection pilot operated in the Eagle Ford Shale play. The main objective of this case study is to understand the flow mechanisms in the reservoir due to hydraulic fracturing of multiple wells and gas injection operations.
A dual porosity numerical reservoir simulation model coupled with geo-mechanics was built to investigate the hydraulic fracturing and flow dynamics of the pilot area using a sophisticated numerical reservoir simulator. The methodology used in this study integrates the hydraulic fracturing process, multi-phase flow and geo-mechanics within the reservoir simulation. In this approach, the change in mean stress for each grid block is implicitly solved together with pressure and the other flow variables using poro-elastic information. Geologic, geo-mechanical and reservoir properties were gathered from the static geo-model. The actual stage-by-stage hydraulic fracture treatment jobs were simulated to investigate the stimulated rock volume (SRV) characteristics of the study wells. The simulation model was calibrated to match the hydraulic fracturing, flow back, depletion and multiple huff and puff cycles. Oil, water and gas production/injection data together with pressure data were matched during calibration. Additional sensitivity runs were performed to examine the potential benefits of gas injection under different operational scenarios.
The results show that the Eagle Ford pilot area is quiet in terms of natural fractures. There is an indication of weak zones that provide preferential connectivity paths for water and gas flow. These weakness points could be related to the lithology or natural fractures. They were defined as easily breakable planar zones in the model. The most important knowledge gained from the calibration of the gas injection period is the establishment of connectivity paths and their poro-elastic behavior during gas injection. The results showed that oil swelling and vaporization of oil into gas are the two mechanisms that impact the huff-n-puff performance. Maintaining most of the injected gas around the huff-n-puff pattern also improves the performance.
Review of Canadian Field Cases of Chemical Floods with Associative Polymer
Authors: Delamaide Eric 
Published: August 2020

Abstract
Polymer flooding is now a well-recognised and mature technology to increase hydrocarbon recovery, used in many parts of the world. Given its success, operators are looking at new opportunities for polymer and are trying to push the technical barriers even further. One of these barriers is high salinity which is detrimental to the economics of polymer floods with standard polymers, and thus requires other solutions.
Associative polymers are polyacrylamide-based polymers well known for their good resistance to high salinity due to their structure and as a result they could be very promising for use in fields with high TDS. However, they have so far seen little use in field applications due to their perceived plugging tendency, high permeability and mobility reduction which make them more adapted to near-wellbore treatment.
Most if not all of the field projects involving associative polymers have taken place in China and in Canada, but little has been published so far. Since public information is available for the Canadian projects, the aim of this paper is to present the field experience of associative polymers in these Canadian projects.
The paper will focus on presenting four field cases, Bodo, Mooney and Suffield (2), all in Western Canada. Bodo is a polymer flood while Mooney and Suffield are both polymer and alkali-surfactant polymer projects. Although public information is not always complete, what is available provides some useful and much needed insight on the performances of associative polymers in the field.
Our analysis of these four field cases suggests that associative polymers can be injected without special difficulty provided they are well chosen, that is they need to be sufficiently associative to outperform HPAM but not too much in order not to plug the reservoir. These results should comfort engineers who have so far been reluctant to use associative polymers due to lack of field experience.
Very few field cases of polymer flood involving associative polymers have been published so far and this paper attempts to shed some light on the performances of associative polymer in some unpublished projects. These positive results may incite engineers working on projects where associative polymers could find a use to consider them.