Unconventional Resources
Numerical and Laboratory Investigations for Maximization of Production from Tight/Shale Oil Reservoirs: From Fundamental Studies to Technology Development and Evaluation Last Reviewed June 2017


The main project goal is to conduct multi-scale laboratory investigations and numerical simulations to (1) identify and quantify the various mechanisms involved in hydrocarbon production from tight systems; (2) describe the thermodynamic state and overall behavior of the various fluids in the nanometer-scale pores of tight media; (3) propose new methods for producing low-viscosity liquids from tight/shale reservoirs; and (4) investigate a wide range of such possible strategies, identify the promising ones, and quantitatively evaluate their performance. Laboratory research will include nano- to core-scale studies, and numerical simulations will examine molecular to field-scale conditions.  By covering the spectrum from fundamental studies to technology development and evaluation, the project team proposes to gain a deeper understanding of the dominant processes that control production from tight reservoirs and to develop a compendium and document the effectiveness of appropriate production strategies. 

Lawrence Berkeley National Laboratory (LBNL)

Gas production from tight gas/shale gas reservoirs over the last decade has been met with spectacular success with the advent of advanced reservoir stimulation techniques (mainly hydraulic fracturing), to the extent that shale gas is now among the main contributors to US hydrocarbon production. This remarkable success has not been matched by similar progress in the production of (relatively) low-viscosity liquid hydrocarbons (including condensates) because of the significant challenges to liquid flow posed by the ultra-low permeability (and the correspondingly high capillary pressures and irreducible liquids saturations) of such reservoirs. These difficulties have limited liquids production to a very low fraction (usually <5%) of the resources-in-place. Increasing the recovery of liquids from these ultra-low permeability systems even by 50-100% over its current very low levels (to a level that is still low in absolute terms, but very significant in relative, hence economic, terms) will not only increase production and earnings, but will also have considerable wider economic implications, as the enhanced recovery will affect reserves and the valuation of companies.

In this multi-phase research effort, LBNL will conduct multi-scale laboratory investigations (nano- to core-scale) and numerical simulations (from molecular to field-scale) to: (1) identify and quantitatively describe mechanisms that control fluid flow and the various system interactions in oil shales; (2) quantitatively describe the behavior of the fluids involved in the production process in the extremely small pore space of shales, leading to promising strategies for enhanced liquid hydrocarbon recovery; (3) analyze the transport of proppants through realistic fractures (including inclined and sharply-angled ones) and evaluate the proppant long-term fate (embedment or pulverization); (4) describe the PVT behavior of fluids in shales, and propose novel approaches as new methods for enhanced production of low-viscosity fluids from tight/shale oil reservoirs after confirmation by laboratory (core-scale) experiments; (5) remove from further consideration potential production strategies that hold limited (if any) promise; and (6) identify and focus study on strategies that appear to have potential for significant enhancement of environmentally-conscious hydrocarbon production (in terms of maximization of both production and recovery), and numerically evaluate their large-scale and long-term performance.

Successful identification of the processes that control production within tight reservoirs may result in processes and methods that could increase production by 50 to 100 percent over the current low recovery rates of approximately 5 percent.  The impact to the industry will be significant and potentially dramatic because of an increase in the amount of hydrocarbon produced  and increases in reserve estimates. The result will be reflected in increased economic benefits to companies and consumers.

In Phase I of this project, LBNL identified the parameters, objectives, and metrics of this study. Numerical simulations were conducted to evaluate production from unfractured/naturally fractured reservoirs and hydraulically fractured reservoirs (Figure 1). Initial simulations serve as reference cases for future research. The “success” of enhanced shale oil recovery will be achieved by an increase in recovery of at least 50% over the life of a shale oil well (3 to 5 years) when compared to the hydraulically fractured reservoir reference case.

  Results of the reference (base) case numerical simulations over a range of permeabilities
  Figure 1: Results of the reference (base) case numerical simulations over a range of permeabilities where solid lines represent the unfractured system and dashed lines represent the hydraulicaly fractured reservoir.

Phase I work also included field scale numerical simulations to assess the recovery enhancement associated with displacement and viscosity reduction in parallel horizontal wells (Figure 2). Simulations have been completed to evaluate enhanced liquid recovery by means of nitrogen (N2), methane (CH4), and carbon dioxide (CO2) displacement and viscosity reduction methods (gas dissolution and thermal stimulation) over a range of permeability. Displacement results indicate very little difference in recovery between N2 and CH4 gasses despite the affinity for CH4 dissolution in oil and its corresponding density and viscosity reductions that are beneficial to recovery (Figure 3). The lack of recovery contrast between the gasses is thought to be attributed to the difficulty of CH4 diffusion into the oil during displacement. Therefore, additional displacement simulations have been completed to investigate the production potential of oil with significant amounts of dissolved CH4 (Figure 3). Results indicate superior recovery of “gassy oil” compared “dead oil” and a much faster recovery over the range of permeability. Results from the CO2 displacement studies indicate greater recovery enhancement with CO2 when compared to N2 and CH4.

Viscosity reduction results associated with thermal stimulation indicate production enhancement after significant lead time and further recovery enhancement when thermal stimulation in initiated prior to production (Figure 4). However, this must be further evaluated against the energy requirements to raise the temperature of the shale system. A new semi-analytical solution (Transformational Decomposition Method [TMD]) has been developed to address the problem of 3D flow through hydraulically fractured media. The TMD solution was validated using published data and can be used to analyze well tests and determine flow properties of producing reservoirs at any desired simulation time without the computational expense of forward time integration. In Phase 1, molecular dynamics (MD) simulations were modified to include chemical reactivity and flow effects in order to understand pore-scale interactions between hydrocarbon molecules and clay surfaces. Exploratory MD runs were completed to determine reactivity in the clay pore molecular model system prior to the introduction of flow.

Detailed schematic of the shale reservoir investigated in the numberical simulations of enhanced oil recovery by means of gas displacement

Figure 2: Detailed schematic of the shale reservoir investigated in the numberical simulations of enhanced oil recovery by means of gas displacement.

Gas displacement and dissolution results from numerical simulations
Figure 3: Gas displacement and dissolution results from numerical simulations showing (a) CH4 and N2 displacement simulations with no discernible difference in production between the two gasses and (b) the effect of dissolved CH4 on enhanced oil recovery for various matrix permeabilities in fractured and unfractured media with superior recovery of "gassy" vs. "dead" oil.

Numerical simulation results of enhanced oil recovery from shale by means of thermal stimulation (viscosity reduction).
Figure 4: Numerical simulation results of enhanced oil recovery from shale by means of thermal stimulation (viscosity reduction).

In Phase I, the laboratory systems for the core-scale enhanced recovery experiments were designed, and initial experiments were completed on Niobrara shale and a well-characterized ceramic. Initial supercritical CO2 (SC-CO2) displacement experiments with the Niobrara shale produced a very small quantity of oil. In order to quantify the process at the laboratory scale, it was determined that a large, well-characterized sample (~1 m3) would be required with an excessive experimental run time. In response, the experimental system was redesigned to ensure lab-scale test durations and sufficient recovery from a well-characterized ceramic medium with known pore space, mineral phase wettability, hydrocarbon content, and starting conditions (Figure 5). Gas displacement results from the redesigned system agree with model results and indicate enhanced recovery with CO2 compared to CH4 and N2 and enhanced recovery with CH4 compared to N2.

Schematic of the redesigned core-scale laboratory system
Figure 5: Schematic of the redesigned core-scale laboratory system

The Advanced Light Source facility at LBNL was used for a series of nano-scale characterization and visualization studies on high quality Niobrara shale samples in Phase I. A comprehensive characterization study was completed on the Niobrara shale via electron microscopy, x-ray diffraction, and x-ray computed tomography (CT) to provide the mineralogy, chemical composition, and texture/microstructure of the samples. Characterization results indicate the Niobrara samples are carbonate rich (55.3 weight %) with a texture highly influenced by the carbonate distribution. While clay content in the samples is typical of many shales (24.1 weight %), chlorite and kaolinite are absent. Organic-rich particles are scattered throughout the samples but do not follow bedding planes. Following sample characterization, a series of imaging experiments were completed to understand micro-scale processes related to oil production techniques from tight shales. Fracture imaging experiments were completed to understand the relationship between textural features and fracture generation. Results from the fracture imaging experiments indicate that generated fractures are irregular and largely controlled by the stress state and bedding planes; however, secondary fractures appear to preferentially form in clay-rich layers (Figure 6). Additional microCT experiments were conducted to understand (1) fracture evolution during the flow of carbonated water and (2) the effect of sweeping a propped fracture with SC-CO2 (Figure 7). Results from the carbonated water flow test indicate increased porosity and permeability associated with worm-holing and preferential dissolution of carbonate-rich structures. Reacted water flood experiments in proppant filled fracture sample demonstrate the dissolution of carbonate along the fracture face and a lack of dissolution at proppant-grain boundaries. In the SC-CO2 sweeping test, results suggest that water in the sample cannot be easily displaced by SC-CO2 and that the effectiveness of SC-CO2 is strongly limited by the presence of trapped water.

Results from the micro-scale fracture imaging experiments
Figure 6: Results from the micro-scale fracture imaging experiments showing (a) fractures appear to be irregular and are primarily controlled by the applied stress state with no apparent interaction with the microstructure and (b) fractures appear irregular and orient with the stress state but the main crack was generated along a bedding plane between a carbonate-rich layer (left) and clay-rich layer (right). The clay-rich layer also contains a number of secondary fractures, while the carbonate-rich layer remains intact.

Local thickness aperature maps of the fracture at different stages of fracture evolution during the flow of carbonate water
Figure 7: (a) Local thickness aperture maps of the fracture at different stages of fracture evolution during the flow of carbonate water. Each step covers the whole sample (~3/8” x 1”) with the inlet at the bottom of the sample. (b) Cross-sections showing the fracture region before (A) and after (B) SC-CO2 sweeping of the propped fracture. Panel (C) shows the baseline image with color highlights in the narrow near-fracture regions that show minor modifications.

The Phase II research effort began on October 1, 2016. In Phase II, field scale simulations continue to be used to investigate a range of enhanced oil recovery techniques. Phase II simulation efforts have focused on the identification of production methods that hold limited promise for removal from further consideration. Results of these simulations indicate poor performance of water injection/drive, steam injection/drive, and water-alternating-gas drive. These behaviors appear to be consistent across a wide range of injection rates, injection pressures, injection schedules/intervals, and reservoir properties. As such, these methods should be abandoned during future considerations of enhanced production techniques in tight/shale oil reservoirs.

In Phase II, molecular dynamics simulations have also been recalibrated to a larger scale system frame, having a pore length of 15 nm in a single montmorillonite crystal. The larger scale model system will have more than 60,000 atoms in the unit frame and will allow for flow simulations with reactive potentials that allow chemical reactions to occur between the fluid and pore walls, as well as within the fluids (Figure 8).

Figure 8: 6x6x6 nm clay cell model with 3x3x2 nm pore used in past simulations with 10,000 atoms. New model will increase size to more than 60,000 atoms with a 3x15x2 nm pore.

In Phase II, the core-scale laboratory system has been updated to include temperature control and the ability to collect fluids from the top or bottom of the apparatus (Figure 9). These modifications to the experimental system allow for the evaluation of enhanced oil recovery techniques that include temperature and gravitational effects. Work is ongoing to complete water and scCO2 injection experiments.   

Figure 9: Modified core-scale laboratory system

Finally, planning is underway to initiate micron-scale proppant transport and fate experiments and simulations. Considerable work has been conducted to develop the numerical methods necessary to model proppant transport and initial micron-scale experiments have been planned to address the role of proppant angularity in the evolution of fractures under increasing stress conditions.  

Current Status (June 2017)
In Phase 1, a field scale model was developed and tested to compare oil production strategies in shale. Although processes such as displacement and viscosity reduction have been found to enhance recovery, increased fracturing and matrix permeability have the greatest impact on recovery enhancement. Core scale laboratory studies have been completed to assess gas displacement and agree with the field scale model results. Nano-scale laboratory investigations have been conducted on the Niobrara shale to assess its response to reactive flow. Finally, a pore scale model was developed that is capable of modeling dissolved hydrocarbon interactions in clay pores. The Phase 1 project ended on March 31, 2016, and the Phase I final report is available below.

The project has been funded for a Phase II research effort to expand upon research conducted in Phase I in order to further investigate mechanisms that control fluid flow in oil shales (including proppant transport and long-term fate) and evaluate improved production strategies that have significant potential to enhance environmentally-conscious hydrocarbon production. The Phase II research effort began on October 1, 2016. The laboratory systems and numerical models are being prepared for experimentation. Field scale simulations continue to investigate a range of enhanced oil recovery techniques. Modifications have been made to the core-scale laboratory system and experiments are underway to assess water and scCO2 injection. Molecular Dynamics simulations have been modified to investigate multiphase flow and chemical reactions within clay pores. Finally, planning is underway to initiate micron-scale proppant transport and fate experiments and simulations.

Project Start: October 1, 2014
Project End: July 31, 2018

DOE Contribution: $899,000
Performer Contribution: $0

Contact Information:
NETL – Stephen Henry (stephen.henry@netl.doe.gov or 304-285-2083)
Lawrence Berkeley National Laboratory - George Moridis, (gjmoridis@lbl.gov or 510-486-4746)

Additional Information:

Numerical and Laboratory Investigations for Maximization of Production from Tight/Shale Oil Reservoirs: From Fundamental Studies to Technology Development and Evaluation (Aug 2017) [PDF]
Presented by Matt Reagan, Lawrence Berkeley National Laboratory, 2017 Carbon Storage and Oil and Natural Gas Technologies Review Meeting, Pittsburgh, PA

Phase I Final Report (July 2016) [PDF] 

2015 Year End Progress Report  [PDF]

Topical Report - Definition of Metrics and Methodology for Screening Production Strategies [PDF]