The overall objective of this project is to increase recovery and sustain production from existing Bakken wells by implementing a novel Enhanced Oil Recovery (EOR) technology that has the potential to resolve some of the pivotal issues associated with gas containment in this field. More specifically, this project seeks to optimize the performance of foam-assisted hydrocarbon gas injection in the Middle Bakken/Three Forks by improving the current scientific understanding of the fundamental mechanisms involved in this process and demonstrating its potential through a field pilot test. An integrated and collaborative framework is proposed to implement these objectives in three different stages: Stage I. Characterization and Chemical Screening/Optimization, to perform laboratory evaluation of foam-based conformance control for injected hydrocarbon gases and customize selected chemicals, as needed, for application under Bakken conditions; Stage II. Multi-scale Core Flooding and Numerical Simulation, to understand the fundamental mechanisms involved in Foam-Assisted Gas Injection (FAGI) EOR using selected formulations and Bakken rock/fluid samples at reservoir conditions and develop/calibrate multi-scale flow models and simulators to predict field performance; and Stage III. Field Pilot Testing Program, to implement this technology in the field through a well-designed pilot test in the Bakken.

University of Wyoming, Laramie, WY 82071

The proliferation of hydraulic fracturing and the low primary recovery rates attainable from unconventional plays provide a strong value case for EOR processes. The large surface area created by fracture networks allows injected fluids to come in contact with the matrix and increase hydrocarbon recovery in formations where more than 90% of the resource is left behind. Miscible gas injection, through continuous flooding or cyclic gas injection (huff and puff), has received a surge of interest in recent years; however, issues associated with gas containment and conformance control were reported in highly heterogeneous formations, such as the Bakken. A recent field application by Dow Chemical in a South Texas shale play overcame some of these issues and yielded significant incremental oil production above those of primary depletion and tertiary gas injection processes. Conformance control could be achieved by injection of hydrocarbon gas and aqueous surfactant solutions to generate stable foam within the fractures. By trapping pockets of gas in brine, gas mobility can be significantly reduced, leading to a substantial rise in pressure gradients across proppant-filled fractures. This establishes the entry pressure needed for gas-to-oil displacements from fracture walls into the matrix. This could become particularly successful when imbibition of surfactant solution into the matrix is suppressed. Foam can potentially enhance the macro-scale sweep efficiency by mitigating the effects of heterogeneity, gas segregation, and viscous instability associated with gas injection.

The outcome of the proposed project will allow operators to maximize the producible oil by using the previously fractured reservoir volumes and existing hydraulically fractured wells while minimizing the number of wells to be drilled, which in turn will lead to informed decisions on their capital investment, development plan, resource evaluation, and reserve replacement. Successful completion of the proposed project will deliver a methodology that allows the development of an EOR method that will be a “game changer” for EOR processes in heterogeneous unconventional oil plays, such as the Bakken.

Once proven successful in the field both technically and economically, this technology may be expanded to augment the play development. This project will greatly benefit the oil and gas industry overall as it will help boost the growth in U.S. onshore oil production and provide greater long-term energy security at lower costs. Furthermore, the success of this project will have a positive environmental impact in two main ways. Firstly, the increased production from existing wells will require fewer wells to be drilled or refractured to efficiently exploit the resource, thus reducing the local environmental impact. Secondly, it gives another economic use for produced natural gas that would have otherwise been flared, thereby reducing emissions. 

• Developed a pad-scale model for foam EOR
  • The multilayer geological (static) model was constructed for the EN-Ortloff DSU, populating the grid cells with rock properties based on geological, log, and core data. 
  • Multiple dynamic reservoir models were built to represent uncertainties in the hydraulic fracture geometry and the presence of natural fractures.
  • Robust representations of the hydraulic fracturing system based on geo-mechanical simulations were incorporated in the reservoir models. The natural fracture representation based on the discrete fracture network modelling was included.
  • Matrix rock properties were upscaled from the multilayer geological model to the dynamic reservoir models with fewer layers using appropriate upscaling methods. 
  • Rock saturation functions such as capillary pressure and relative permeability curves were developed from measured data and correlation-based models.
  • Dual porosity/dual permeability simulations with a fine grid system were applied for the hydraulic and natural fracture representations.
  • Several compositional fluid models based on an equation of state (EOS) were developed for use in simulation studies to capture the compositional impacts of the foam assisted gas injection EOR processes.
  • Good history match was achieved between predictions of the multiple models and all available production data in the time interval from August 2010 to January 2018. 
  • The model prediction capabilities were validated demonstrating that:
    • The model predictions of oil production to Year 2050 are consistent with production type curves (analytical decline curves of oil production). 
    • The primary depletion predictions in the time interval from January 2018 to March 2020 are matching field production data. The models were run in the prediction mode in this time interval. 
  • An extensive review of existing foam flow models was conducted.
  • An engineering-based foam flow model was implemented for simulation studies in the Eclipse reservoir simulator. This foam flow model uses a ‘mobility reduction’ method for the gas phase entrapped in the foam-phase and appropriate modifications to the gas viscosity were implemented.
• Identified optimum chemical formulation for cycle 1 of pilot test
  • More than forty (40) foaming formulations were investigated for their aqueous stability information brine at high temperature (115 C) and the top five (5) chemicals were identified initially.
  • Bulk foam tests were performed for all the selected formulations (surfactants), three surfactants XUR-A, XUR-B, and XUR-C, and their low-temperature (LT) (winterized) versions XUR-ALT, XURBLT, and XUR-CLT. The winterized versions performed better compared to non-winterized ones in this test.
  • The selected formulations went through Static Adsorption and Emulsion Tendency Tests for further screening. Static adsorption for rock samples and proppant grains were determined. During these tests, the winterized versions XUR-ALT, XUR-BLT, and XUR-CLT performed better and were selected for further studies.
  • The interactions of the selected formulations with brine, rocks, and oil were studied. XUR-ALT and XUR-CLT surfactants adsorbed significantly on calcite but much less on silica. On the other hand, the XUR-BLT surfactant showed little adsorption on both minerals (230-300 ng/cm2).
  • Contact angle measurements on aged reservoir rock chips were performed with Bakken crude oil, 200,000 ppm brine, and different surfactant solutions at high-pressure and high-temperature (115 °C and 3,500 psi) conditions. All three surfactants reduced the contact angle, however, XURCLT caused a lower degree of wettability alteration compared to those of XUR-ALT and XUR-BLT.
  • Spontaneous imbibition tests were performed on unaged and aged Berea Sandstone and MNCB
  • Limestone rock samples to probe the effects of the surfactants on imbibition into the rock matrix. These tests were conducted with both low salinity and high salinity brines. 
  • Foamability and foam stability tests were conducted with the surfactants, and initial insights into an optimum gas fraction, surfactant concentration, and flow rates were obtained. 
  • A state-of-the-art foam generation system was fabricated to perform significantly more tests examining the effect of other parameters on foam quality, stability, and foam flow behavior.
• Determined Bakken reservoir rock wettability 
  • A high-pressure, high-temperature (HPHT) interfacial tension and contact angle (IFT/CA) measurement system is pressure tested.
  • Bakken crude oil sample is prepared and filtered for the measurements.
  • Bakken formation brine and planned low-salinity injection brine are synthesized based on the compositions provided by Hess Corporation.
  • Middle Bakken reservoir rock samples are acquired, solvent-cleaned using flow-through techniques, cut to appropriate sizes, and polished before the contact angle measurements.
  • A tailored aging procedure is developed for tight reservoir samples and used to determine the wettability of Bakken rock samples.
  • To characterize the reservoir rock wettability, static contact angles are measured on cleaned and aged reservoir rock samples at ambient and elevated temperature and pressure conditions (115 °C and 3,500 psi) with Bakken crude oil and blank brine solutions.
  • Selected surfactant formulations (foaming agents) are tested for their ability to alter aged rock wettability.

A state-of-the-art reservoir conditions laboratory was designed and fabricated from scratch to perform foam evaluation tests at reservoir conditions. The facility has enormous capacity, and therefore it enables a significant number of tests in a relatively short amount of time. Foam generation and evaluation experiments are conducted on a large scale for different surfactants at HPHT conditions with different proppant packs. These tests are performed to investigate the sensitivities of the foam performance to changes in key foam parameters. Specifically, several hundred foam generation and evaluation tests have been conducted at 3,500 psi and 115 °C pressure and temperature conditions using water-wet and oil-wet proppant packs in order to optimize surfactant concentration, brine salinity, fraction of the injected gas, and other foam parameters. An ACS surfactant and QD nanoparticles have also been used in these tests. Foam strength and stability were characterized by measuring half-life and apparent viscosity, and successively the optimum conditions for foam performance are investigated.

A series of foam-gas injection simulations have been conducted to establish optimal foam-gas injection strategy for Phase-I of the field test. In the preliminary simulations, default parameters based on existing laboratory and field data for conventional reservoirs were used. The results indicate that foam treatment can be a valuable tool for increasing oil production in the planned EN-Ortloff pilot. In addition, foam gas injection helps minimize gas production, which reduces the load on the facilities and lessens the potential for flaring. 

Given the COVID-19 shutdown and collapse of the oil market, Hess Corporation decided to adjust the schedule for the foam injection task of this project to the year 2022. Other activities, such as laboratory experiments and reservoir simulation and optimization, were continued as planned. It must be noted that the adjusted schedule due to COVID-19 provided the University of Wyoming team with opportunities to deepen technical understandings related to foam generation and optimization, which has already resulted in various noticeable technical advances. The team UW developed a new reservoir conditions foam evaluation laboratory facilitating simultaneous testing of various surfactants/foaming chemicals under different conditions. This laboratory will be significantly beneficial to the field pilot test as it is used to determine optimized foam parameters for the modeling and simulation task as well as the field pilot test.
 

$8,000,000

$2,003,287

NETL – Scott Beautz (scott.beautz@netl.doe.gov or 918-497-8766)
University of Wyoming – Mohammad Piri (mpiri@uwyo.edu or 307-766-3922)