Wellbore instability in hard brittle shale is a critical topic related to the effective exploitation of shale gas resources. This review first introduces the physical-chemical coupling theories applied in shale wellbore stability research, including total water absorption method, equivalent pore pressure method, elasticity incremental method of total water potential and non-equilibrium thermodynamic method. Second, the influences of water activity, membrane efficiency, clay content and drilling fluid on shale wellbore instability are summarized. Results demonstrate that shale and drilling fluid interactions can be the critical factors affecting shale wellbore stability. The effects of thermodynamics and electrochemistry may also be considered in the future, especially the microscopic reaction of shale and drilling fluid interactions. An example of this reaction is the chemical reaction between shale components and drilling fluid.

Surfactant enhanced oil recovery (EOR) includes surfactant flooding and surfactant stimulation. The main functions of surfactants are to reduce interfacial tension and wettability alteration. This paper is to review the EOR technology related to surfactant injection. The reviewed topics include the following:

• Surfactant EOR mechanisms

• Factors affecting interfacial tension

• Trapping number

• Screening criteria

• Laboratory work

• Numerical simulation work

• Summary of pilot and large-scale applications

• Surfactants used

• Salinity gradient

• Surfactant EOR in carbonate reservoirs

• Surfactant EOR in shale reservoirs

Pore size determination of hydrocarbon reservoirs is one of the main challenging areas in reservoir studies. Precise estimation of this parameter leads to enhance the reservoir simulation, process evaluation, and further forecasting of reservoir behavior. Hence, it is of great importance to estimate the pore size of reservoir rocks with an appropriate accuracy. In the present study, a modified J-function was developed and applied to determine the pore radius in one of the hydrocarbon reservoir rocks located in the Middle East. The capillary pressure data vs. water saturation (P_c-S_w) as well as routine reservoir core analysis include porosity (φ) and permeability (k) were used to develop the J-function. First, the normalized porosity (φ_z), the rock quality index (RQI), and the flow zone indicator (FZI) concepts were used to categorize all data into discrete hydraulic flow units (HFU) containing unique pore geometry and bedding characteristics. Thereafter, the modified J-function was used to normalize all capillary pressure curves corresponding to each of predetermined HFU. The results showed that the reservoir rock was classified into five separate rock types with the definite HFU and reservoir pore geometry. Eventually, the pore radius for each of these HFUs was determined using a developed equation obtained by normalized J-function corresponding to each HFU. The proposed equation is a function of reservoir rock characteristics including φ_z, FZI, lithology index (J^*), and pore size distribution index (ɛ). This methodology used, the reservoir under study was classified into five discrete HFU with unique equations for permeability, normalized J-function and pore size. The proposed technique is able to apply on any reservoir to determine the pore size of the reservoir rock, specially the one with high range of heterogeneity in the reservoir rock properties.

Study on the residual oil distribution regularity is the important thing during the middle and later stage of the oilfield. With understanding and development of oilfield, the research methods of remaining oil are varied. Well block A is a low permeability oilfield and complex relationship between injection wells and production wells. The well pattern has low control of sand body. Based on the characteristics and the geological and dynamic data, technology of integrated 3-D geological modeling with reservoir numerical simulation is ensured to study the residual oil. Finally, deposition facies and flowing units are studied to analyze the residual oil distribution regularity. As a result, the types of residual oil were confirmed and the basis for the following development adjustment of the well block is provided.

Greater complexity is involved in the transient pressure analysis of horizontal oil wells in contrast to vertical wells, as the horizontal wells are considered entirely horizontal and parallel with the top and underneath boundaries of the oil reserve. Therefore, there is an essential need to estimate productivity of horizontal wells accurately to examine the effectiveness of a horizontal well in terms of technical and economic prospects.

In this work, novel and rigorous methods based on two different types of intelligent approaches including the artificial neural network (ANN) linked to the particle swarm optimization (PSO) tool are developed to precisely forecast the productivity of horizontal wells under pseudo-steady-state conditions. It was found that there is very good match between the modeling output and the real data taken from the literature, so that a very low average absolute error percentage is attained (e.g., <0.82%). The developed techniques can be also incorporated in the numerical reservoir simulation packages for the purpose of accuracy improvement as well as better parametric sensitivity analysis.

Hydraulic fracturing combined with horizontal drilling has been the technology that makes it possible to economically produce natural gas from unconventional shale gas or tight gas reservoirs. Hydraulic fracturing operations, in particular, multistage fracturing treatments along with horizontal wells in unconventional formations create complex fracture geometries or networks, which are difficult to characterize. The traditional analysis using a single vertical or horizontal fracture concept may be no longer applicable. Knowledge of these created fracture properties, such as their spatial distribution, extension and fracture areas, is essential information to evaluate stimulation results. However, there are currently few effective approaches available for quantifying hydraulic fractures in unconventional reservoirs.

This work presents an unconventional gas reservoir simulator and its application to quantify hydraulic fractures in shale gas reservoirs using transient pressure data. The numerical model incorporates most known physical processes for gas production from unconventional reservoirs, including two-phase flow of liquid and gas, Klinkenberg effect, non-Darcy flow, and nonlinear adsorption. In addition, the model is able to handle various types and scales of fractures or heterogeneity using continuum, discrete or hybrid modeling approaches under different well production conditions of varying rate or pressure. Our modeling studies indicate that the most sensitive parameter of hydraulic fractures to early transient gas flow through extremely low permeability rock is actually the fracture-matrix contacting area, generated by fracturing stimulation. Based on this observation, it is possible to use transient pressure testing data to estimate the area of fractures generated from fracturing operations. We will conduct a series of modeling studies and present a methodology using typical transient pressure responses, simulated by the numerical model, to estimate fracture areas created or to quantity hydraulic fractures with traditional well testing technology. The type curves of pressure transients from this study can be used to quantify hydraulic fractures in field application.

Precipitation of heavy hydrocarbon components such as Wax and Asphaltenes are one of the most challenging issues in oil production processes. The associated complications extend from the reservoir to refineries and petrochemical plants. Precipitation is most destructive when the affected areas are hard to reach, for example the wellbore of producing wells. This work demonstrates the effect of adjusting choke valve sizes on thermodynamic parameters of fluid flowing in a vertical well. Our simulation results revealed optimum choke valve sizes that could keep producing vertical wells away from Asphaltene precipitation. The results of this study were implemented on a well in Darquin Reservoir that had been experiencing asphaltene precipitation. Experimental analysis of reservoir fluid, Asphaltene tests and thermodynamic simulations of well column were carried out and the most appropriate size of choke valve was determined. After replacing the well's original choke valve with the suggested choke valve, the Asphaltene precipitation problem diminished.

Acid fracturing treatment is the key technique for stimulation and stable production in carbonate reservoirs. In order to improve the carbonate reservoirs acid fracturing effect, in this paper, with a large number of experiments as the main research methods, study on influencing factors of acid-fracturing effect for carbonate reservoirs from increase the effective distance of living acid, increase acid corrosion eched fracture conductivity, reduce the acid fluid loss, etc. The effective distances of live acid calculated with reacted acid limitations measured in different acid systems are quite different from those calculated according to previous standard. Fracture conductivity is one of the key parameters that affects acid fracturing effects, but it's difficult to be predicted accurately due to the strong randomness of acid-rock reaction as well as various influence factors. Analyses of the impacts on fracture conductivity resulted from the rock embedment intensity, closure stress, acid dosage, rock-acid contact time, acid fluid loss, acid pumping rate through self-developed small-core fracture capacity test instrument. Fluid loss during acid fracture can be well controlled by thickened liquid as well as solid particles, but formation damage occurs inevitably. Foamed acid is a specific fluid with high viscosity, low fluid loss, small friction resistance, good retarding property, strong fracture making ability, easy flowback and low damage, which is an ideal acid system for low pressure and low permeability carbonate reservoirs. In this paper, the theoretical study on percolation mechanism and fluid-loss control mechanism of foam (acid) in porous medium are presented with the help of visual microscopic model fluid drive unit.

Aiming at the large error in productivity predication and incomplete consideration in completion parameters design of perforated horizontal well, a model which coupled the relationship of pressure and flow rate in reservoir seepage, near-wellbore inflow and wellbore flow was established. The impact of near-wellbore heterogeneity, wellbore flow pressure drop and completion parameters on the inflow profile of horizontal well is analysed. Studies showed that with a stronger near-wellbore heterogeneity, the inflow profile would fluctuate more seriously. Perforation density had a great influence on the inflow profile and local changes of it would bring a shunt effect. Completion design of variable density perforated horizontal well with an optimized inflow profile which was close to a standard profile would improve the horizontal well development effect. The achievement can provide directive meanings to productivity predication and completion parameters design of horizontal wells in oilfield.

Pore volume of Cumulative water injection is one of the factors for evaluating water flood effect in a water flood oil field. In previous study, there were limited lab studies for evaluating oil displacement efficiency. A method to characterize the distribution of pore volume of cumulative water injection is proposed in this paper, and it is verified by a five-spot water flooding streamline simulation model. The logarithmic relation between pore volume of cumulative water injection and water saturation is established by regression. An inflection point and limit point of cumulative water injection pore volume are identified. Current simulation model indicates inflection point appears after 2-5 pore volume (PV) injection, and limit point appears after 15-25 PV injection. Both inflection and limit point vary in different regions of reservoir.

This paper presents the development and application of an innovative code to extract in an automated way data from the thermo-hydraulic simulator Olga. The results show that the tool can significantly reduce the time needed for the data extraction procedure and increase the reliability of results due to the fact that there is no more the need of the human operator. Moreover, during the data extraction phase, the Olga code is available for running different simulations allowing to optimize the use of this resource.

This paper provides a novel three-dimensional meshless Galerkin for horizontal well reservoir simulation. The pressure function is approached by moving least-square method which consists of weight function, basic function and coefficient. Based on Galerkin principle and use penalty function method, the paper deduces the meshless Galerkin numerical linear equations. Cut off the pressure distribution of the horizontal section from the simulation database of horizontal well reservoir. It demonstrates that meshless Galerkin is a feasible numerical method for the horizontal well reservoir simulation. It is useful to research complex reservoir.