James J. Sheng

Status of Polymer-Flooding Technology

Polymer flooding is the most commonly applied chemical enhanced-oil-recovery technique. This paper provides an update on the status of polymer-flooding technology, focusing more on field applications than on theoretical and laboratory research. It covers the following topics: • Mechanisms of polymer flooding • Polymers used • Polymer-solution stability • Technical screening criteria • Laboratory and simulation work • Performance-monitoring technique • Summary of pilots and large-scale applications • Experience and learning from field projects • Polymer flooding in heavy-oil reservoirs • Polymer viscoelastic properties • Problems associated with polymer flooding and their solutions • Future developments The data and analysis presented in this paper will give readers updated information describing polymer flooding, as well as a guide to the relevant research. Survey data will also provide operators with reference data for project design and optimization.

Critical Review of Foamy Oil Flow

Abstract‘Foamy oil flow’ is a term coined to describe a form of two‐phase oil‐gas flow that appears to occur during solution gas drive in some heavy oil reservoirs and does not fit the classical models of two‐phase flow. Most of the evidence supporting the presence of this unusual flow mechanism is circumstantial and comes from attempts to explain much higher than expected well productivity and primary recovery factors in several heavy oil reservoirs. This paper is a review of the available literature on foamy oil flow in primary production of heavy oils under solution gas drive.The mechanisms operating in solution gas drive in heavy oil reservoirs are briefly discussed. The issues related to supersaturation in oil phase, bubble nucleation, critical gas saturation, and relative permeability are discussed. The possible role of rate processes related to the release of solution gas and the formation of a segregated gas phase is reviewed. The pore‐scale mechanisms involved in creation and propagation of dispersed gas flow are discussed. Several published mathematical models of foamy solution gas drive are reviewed with focus on their limitations.The review shows that the theoretical and experimental investigations of foamy oil flow are still in early stages. Although the occurrence of foamy oil flow has been verified in laboratory experiments, its existence at the reservoir scale has not been confirmed. The theoretical understanding of the mechanisms underlying foamy oil flow remains poor.

Modelling Foamy Oil Flow in Porous Media

This paper describes a dynamic model for the simulation of foamy oil flow in porous media. The model includes expressions for the rate processes of nucleation, bubble growth and disengagement of dispersed gas bubbles from the oil. The model is used to simulate experimental results pertaining to primary depletion tests conducted in a sand pack. Using the model to interpret experimental results indicated that, although the lifetimes of supersaturation and dispersed gas bubbles may be short, supersaturated conditions are likely to exist, and dispersed gas bubbles are likely to be present during the entire production period, as long as the pressure continues to decline at a high rate. The model developed in this paper gave better agreement with experimental data than other proposed models. The effect of foamy oil flow increases as the rate of pressure decline increases.

Evaluation of the EOR Potential in Hydraulically Fractured Shale Oil Reservoirs by Cyclic Gas Injection

Gas flooding in fractured reservoirs may not be an effective avenue for improving oil recovery because the injected fluids could break-through to production wells via the fracture network. A cyclic injection scheme is one way to solve this problem. In this study, the authors propose to use cyclic gas injection to improve hydraulically fractured shale oil recovery. They used a simulation approach to evaluate the enhanced oil recovery (EOR) potential from cyclic gas injection. The simulation results indicate that total oil recovery can be increased up to 29% by cyclic gas injection, compared with the 6.5% recovery from the primary depletion. If a higher pressure is used to reach fully miscibility with reservoir oil and more cycles are employed, more oil recovery is expected.

Evaluate EOR Potential in Fractured Shale Oil Reservoirs by Cyclic Gas Injection

The current technique to produce shale oil is to use horizontal wells with multi-stage stimulation. However, the primary oil recovery factor is only a few percent. The low recovery and the abundance of shale reservoirs provide a huge potential for enhanced oil recovery. Well productivity in shale oil and gas reservoirs primarily depends upon the size of fracture network and the stimulated reservoir volume (SRV) which provides highly conductive conduits to communicate the matrix with the wellbore. The natural fracture complexity is critical to the well production performance and it also provides an avenue for injected fluids to displace the oils. However, the disadvantage of flooding in fractured reservoirs is that the injected fluids may break through to production wells via the fracture network. Therefore, a preferred method is to use cyclic gas injection to overcome this problem. In this paper, we use a numerical simulation approach to evaluate the EOR potential in fractured shale oil reservoirs by cyclic gas injection. Simulation results indicate that the stimulated fracture network contributes significantly to the well productivity via its large contact volume with the matrix, which prominently enhances the macroscopic sweep efficiency in secondary cyclic gas injection. In our previous simulation work, the EOR potential was evaluated from planar traverse fractures. In this paper, we examine the EOR potential by including the effect of fracture networks. Therefore, a higher oil recovery potential is demonstrated. The impacts of fracture spacing density and stress dependent fracture conductivity on the ultimate oil recovery are also investigated. In a case where the fracture network spacing is 100 ft and the fracture network is 100% stimulated, it can achieve more than 60% of incremental oil recovery. The results presented in this paper demonstrate an EOR potential by cyclic gas injection in fractured shale oil reservoirs.

Research on oxidation kinetics of tight oil from Wolfcamp field

ABSTRACT Thermogravimetry and differential scanning calorimetry were performed on a tight oil that was collected from the Wolfcamp shale reservoir, USA. The results indicate that although the oil has similar properties to those of a light oil, it shows similar thermal-oxidative behaviors to those of a heavy oil. Kinetic data of the tight oil as activation energy and frequency factor were estimated by the Arrhenius method. This kinetic analysis could provide us insight to characterize the reactivity of the tight oil, and establish parameter values for kinetic models used in the numerical simulation of the air injection process.

Effect of Water Salinity on Shale Reservoir Productivity

It is well known that rocks containing water-reactive clays may swell when contacting with fresh water. In a conventional formation, this swelling may cause wellbore stability problem or damage formation by reducing its permeability. However, the effect of water salinity on shale rocks may be different. This issue is investigated in this paper. Shale rocks were immersed in water of different salinities. Shale rocks used were Mancos, Marcellus, Barnett and Eagle Ford. Different concentrations of NaCl and KCl salt solutions from 0% to 30% by weight were added in the water. It was observed that Mancos core plugs were crushed into loose grains (fragmented) at low salinity solutions up to 15%. Barnett core plugs showed consecutive cracks along bedding planes at low salinities. Minor cracks were seen on Marcellus, while no cracks at all were found in Eagle Ford core plugs at low salinities. When the shale plugs were saturated with oil, 2-15% oil was recovered by water spontaneous imbibition, depending on water salinity and rock mineralogy. Similar observations were made when shale core plugs were applied to an overburden pressure. The results from this paper help us to understand the drive mechanisms in shale oil and shale gas reservoirs. It also stimulates us to explore new ways to improve oil and gas recovery in shale reservoirs. Key words : Water salinity; Shale reservoir; Oil and gas recovery

Enhanced Recovery of Crude Oil From Shale Formations by Gas Injection in Zipper-fractured Horizontal Wells

The zipper-frac technique is implemented in two adjacent horizontal wells to maximize the exposure of shale rocks. The hydraulic fractures are propagated in a manner in which they are connected with natural fracture network to improve the fracture complexity. In this study, the authors exploit the advantage of stimulated fracture complexity to access more of the hydrocarbons trapped in very low permeability of shale matrix. The recovery process efficiencies by cyclic CO2 injection and CO2 flooding in zipper-fractured horizontal wells are compared. The role of diffusion recovery mechanism in recovering oil from fractured shales will be discussed.

A proposed dynamic model for foamy oil properties

To simulate foamy oil flow, it is first important to calculate foamy oil properties properly. Several previous investigators have made such an effort. However, their approaches do not account for the time (or rate) dependent changes in foamy oil characteristics. This paper proposes a methodology for including the dynamic processes in the calculation of foamy oil properties, using molar variables. The issues of bubble nucleation, growth and decay are also reviewed and discussed. The basic foundation of this model rests on the theoretical results and experimental observations of nucleation, bubble growth and decay. The model is verified by matching the calculated results with experimental data. The results calculated from this model show how the foamy oil properties vary with pressure and time. The non-equilibrium processes of both bubble growth and decay are important for the calculation of foamy oil properties. However, the rate of decay for the entrained gas is most significant in foamy oil flow. This method of calculating foamy oil properties provides the basics for developing numerical simulation models of foamy oil flow. The results from this model may also be useful for well testing analysis in foamy oil reservoirs.

Investigation of asphaltene deposition mechanisms during CO2 huff-n-puff injection in Eagle Ford shale

ABSTRACT In this study, laboratory tests were conducted to investigate the asphaltene deposition mechanisms during CO2 huff-n-puff injection in an Eagle Ford shale core using Wolfcamp shale oil. The permeability reduction due to asphaltene deposition by mechanical plugging and adsorption mechanisms were determined using the n-Heptane and toluene reverse flooding, respectively. The results showed that 83% of the total permeability reduction is due to asphaltene deposition by mechanical plugging mechanism, while 17% of the total permeability reduction is due to asphaltene deposition by adsorption mechanism. The critical interstitial velocity for entrainment of asphaltene deposition was around 0.0008 cm/sec.