Modified Horizontal Well Productivity Model for a Tight Gas Reservoir Subjected to Non-Uniform Damage and Turbulence

Tight gas reservoirs are finding greater interest with the advancement of technology and realistic prediction of flow rate and pressure from such wells are critical in project economics. This paper presents a modified productivity equation for tight gas horizontal wells by modifying the mechanical skin factor to account for non-uniform formation damage along with the incorporation of turbulence effect in the near-wellbore region. Hawkin’s formula for calculating skin factor considers the radius of damage as a constant value, which is less accurate in low-permeability tight gas reservoirs. This paper uses a multi-segment horizontal well approach to develop the local skin factors and the equivalent skin factor by equating the total production from the entire horizontal well to the sum of the flow from individual segmented damaged zones along the well length. Conical and horn-shaped damaged profiles are used to develop the equivalent skin used in the horizontal well productivity equation. The productivity model is applied to a case study involving the development of a tight gas field with horizontal wells. The influence of the horizontal well length, damaged zone permeability, drainage area, reservoir thickness, and wellbore diameter on the calculated equivalent skin (of a non-uniform skin distribution) and the flow rate (with turbulence and no turbulence) are investigated. The results obtained from this investigation show significant potential to assist in making practical decisions on the favorable parameters for the success of the field development in terms of equivalent skin factor, flow rate, and inflow performance relationships (IPR).

High-Resolution and Multimaterial Fracture Productivity Calculator for the Successful Design of Channel Fracturing Jobs

We developed a high-resolution fracture productivity calculator to enable fast and accurate evaluation of hydraulic fractures modeled using a fine-scale 2D simulation of material placement. Using an example of channel fracturing treatments, we show how the productivity index, effective fracture conductivity, and skin factor are sensitive to variations in pumping schedule design and pulsing strategy. We perform fracturing simulations using an advanced high-resolution multiphysics model that includes coupled 2D hydrodynamics with geomechanics (pseudo-3D, or P3D, model), 2D transport of materials with tracking temperature exposure history, in-situ kinetics, and a hindered settling model, which includes the effect of fibers. For all simulated fracturing treatments, we accurately solve a problem of 3D planar fracture closure on heterogenous spatial distribution of solids, estimate 2D profiles of fracture width and stresses applied to proppants, and, as a result, obtain the complex and heterogenous shape of fracture conductivity with highly conductive cells owing to the presence of channels. Then, we also evaluate reservoir fluid inflows from a reservoir to fracture walls and further along a fracture to limited-size wellbore perforations. Solution of a productivity problem at the finest scale allows us to accurately evaluate key productivity characteristics: productivity index, dimensional and dimensionless effective conductivity, skin factor, and folds of increase, as well as the total production rate at any day and for any pressure drawdown in a well during well production life. We develop a workflow to understand how productivity of a fracture depends on variation of the pumping schedule and facilitate taking appropriate decisions about the best job design. The presented workflow gives insight into how new computationally efficient methods can enable fast, convenient, and accurate evaluation of the material placement design for maximum production with cost-saving channel fracturing technology.

Developing features of the near-bottomhole zones in productive formations at fields with high gas saturation of formation oil

The article studies the formation features of the bottomhole zones in productive formations during operation of production wells in the north of the Perm Territory. Their distinctive feature is the high gas saturation of formation oil. The most widely used parameter in Russian and world practice – the skin factor was used as a criterion characterizing the state of the bottomhole zone. Analysis of scientific publications has shown that one of the main problems of applying the skin factor to assess the state of bottomhole zones is the ambiguity of interpretations of its physical meaning and the impossibility of identifying the prevailing factors that form its value. The paper proposes an approach to identifying such factors in the conditions of the fields under consideration, based on multivariate correlation-regression analysis. Choice of this tool is due to the complexity of the processes occurring in the “formation – bottomhole zone – well” system. When describing complex multifactorial processes, the chosen method demonstrates a high degree of reliability. For a large number of wells in the region, significant material was collected and summarized, including the results of determining the skin factor (1102 values) during hydrodynamic investigations, as well as data on the values ​​of various geological and technological indicators, which can probably be statistically related to the value of the skin factor. A series of multidimensional mathematical models has been built; the skin factor was used as a predicted parameter, and data on the values ​​of geological and technological indicators were used as independent indicators. Analysis of the constructed models is a key stage of this study. Set of parameters included in the multidimensional models, sequence of their inclusion and contribution to the total value of the achieved determination coefficient as the main indicator for the performance of the constructed models were studied. It has been established that the main factor influencing the state of the bottomhole zone is oil degassing. Significant differences in the formation features of the skin factor in the terrigenous and carbonate sediments at the fields under consideration have been determined.

Novel Simulator for Design and Analysis of Matrix Acidizing Jobs with Fluoroboric Acid in Sandstone Reservoirs

Matrix acidizing with fluoroboric acid (HBF4) has gained special attention as not only it provides deeper penetration of in – situ generated hydrofluoric acid, but also stabilizes formation fines by binding them to the pore surface. While numerous mathematical models exist in literature for design and evaluation of conventional mud acid treatments, fewer attempts have been made in developing a lab validated model that can do so for fluoroboric acid treatments. This paper presents a novel mathematical model that has been developed taking into account the chemical kinetics and equilibrium aspects of important reactions and fluid flow inside the reservoir rock. The solution to the governing equations has been obtained through tools of computational fluid dynamics (CFD). The model has been validated rigorously through use of state-of-the-art core flooding and ion chromatography setups. The resulting simulator can be used to design an optimum fluoroboric acid treatment by analysing the effects of all the important factors including reservoir temperature, formation mineralogy and job execution details like initial acid concentration, pumping rate, job volume and shut-in time post treatment. Simulation results with the developed model indicate that although penetration of fluoroboric acid is much larger compared to mud acid, its overall effect on skin factor is inferior for temperatures less than 90 °C. Stimulation in such wells should be preferred with mud acid which can be followed by fluoroboric acid for fines stabilization. For temperatures more than 120 °C, stimulation effects of fluoroboric acid become comparable to that of mud acid. Under these conditions, it can be used as an alternate fluid to mud acid to prevent issues of secondary and tertiary precipitation. It is found that major stimulation benefits with fluoroboric acid are realized during pumping and subsequent shutting of well, which is a common practice with fluoroboric acid, has relatively smaller effect on skin factor. Apart from design and evaluation of fluoroboric acid treatments, the simulator can also be used for analyzing mud acid and mud acid followed by fluoroboric acid treatments thus enabling the user to select and design the best suited treatment for a given well.

A New Evaluation of Skin Factor in Inclined Wells with Anisotropic Permeability

Oil and gas well productivity can be affected by a number of different skin factors, the combined influences of which contribute to a well’s total skin factor. The skin caused by deviated wells is one such well-known factor. The present study aimed to investigate skin effects caused by deviated well slants when considering vertical-to-horizontal permeability anisotropy. The research employed computational fluid dynamics (CFD) software to simulate fluid flows in inclined wells through the injection of water with Darcy flow using 3D geometric formations. The present work investigates the effects of four main characteristics—namely, the permeability anisotropy, wellbore radius, reservoir thickness, and deviation angle—of open-hole inclined wells. Additional investigations sought to verify the effect of the direction of perforations on the skin factor or pressure drop in perforated inclined wells. In the case of an inclined open hole well, the novel correlation produced in the current study simplifies the estimation of the skin factor of inclined wells at different inclination angles. Our comparison indicates good agreement between the proposed correlation and available models. Furthermore, the results demonstrated a deviation in the skin factor estimation results for perforated inclined wells in different perforation orientation scenarios; therefore, existing models must be improved in light of this variance. This work contributes to the understanding and simulation of the effects of well inclination on skin factor in the near-wellbore region.

A New Method for Research on Unsteady Pressure Dynamics and Productivity of Ultralow-Permeability Reservoirs

In the numerous low-permeability reservoirs, knowing the real productivity of the reservoir became one of the most important steps in its exploitation. However, the value of permeability interpreted by a conventional well-test method is far lower than logging, which further leads to an inaccurate skin factor. This skin factor cannot match the real production situation and will mislead engineer to do an inappropriate development strategy of the oilfield. In order to solve this problem, key parameters affecting the skin factor need to be found. Based on the real core experiment and digital core experiment results, stress sensitivity and threshold pressure gradient are verified to be the most influential factors in the production of low-permeability reservoirs. On that basis, instead of a constant skin factor, a well-test interpretation mathematical model is established by defining and using a time-varying skin factor. The time-varying skin factor changes with the change of stress sensitivity and threshold pressure gradient. In this model, the Laplace transform is used to solve the Laplace space solution, and the Stehfest numerical inversion is used to calculate the real space solution. Then, the double logarithmic chart of dimensionless borehole wall pressure and pressure derivative changing with dimensionless time is drawn. The influences of parameters in expressions including stress sensitivity, threshold pressure, and variable skin factor on pressure and pressure derivative and productivity are analyzed, respectively. At last, the method is applied to the well-test interpretation of low-permeability oil fields in the eastern South China Sea. The interpretation results turn out to be reasonable and can truly reflect the situation of low-permeability reservoirs, which can give guidance to the rational development of low-permeability reservoirs.

Comparison of Crushed-Zone Skin Factor for Cased and Perforated Wells Calculated with and without including a Tip-Crushed Zone Effect

A number of different factors can affect flow performance in perforated completions, such as perforation density, perforation damage, and tunnel geometry. In perforation damage, any compaction at the perforation tunnels will lead to reduced permeability, more significant pressure drop, and lower productivity of the reservoir. The reduced permeability of the crushed zone around the perforation can be formulated as a crushed-zone skin factor. For reservoir flow, earlier research studies show how crushed (compacted) zones cause heightened resistance in radially converging vertical and horizontal flow entering perforations. However, the effects related to crushed zones on the total skin factor are still a moot point, especially for horizontal flows in perforations. Therefore, the present study will look into the varied effects occurring in the crushed zone in relation to the vertical and horizontal flows. The experimental test was carried out using a geotechnical radial flow set-up to measure the differential pressure in the perforation tunnel with a crushed zone. Computational fluid dynamics (CFD) software was used for simulating pressure gradient in a cylindrical perforation tunnel. The single-phase water was radially injected into the core sample with the same flow boundary conditions in the experimental and numerical procedures. In this work, two crushed zone configuration scenarios were applied in conjunction with different perforation parameters, perforation length, crushed zone radius, and crushed zone permeability. In the initial scenario, the crushed zone is assumed to be located at the perforation tunnel’s side only, while in the second scenario, the crushed zone is assumed to be located at a side and the tip of perforation (a tip-crushed zone). The simulated results indicate a good comparison with regard to the two scenarios’ pressure gradients. Furthermore, the simulations’ comparison reveals another pressure drop caused by the tip crushed zone related to the horizontal or plane flow in the perforations. The differences between the two simulations’ results show that currently available models for estimating the skin factor for vertical perforated completions need to be improved based on which of the two cases is closer to reality. This study has presented a better understanding of crushed zone characteristics by employing a different approach to the composition and shape of the crushed zone and permeability reduction levels for the crushed zone in the axial direction of the perforation.

Quantifying the partial penetration skin factor for evaluating the completion efficiency of vertical oil wells

An oil well's productivity is generally considered the standard measure of the well's performance. However, productivity depends on several factors, including fluid characteristics, formation damage, the reservoir's formation, and the kind of completion the well undergoes. How a partial completion can affect a well's performance will be investigated in detail in this study, as nearly every vertical well is only partially completed as a result of gas cap or water coning issues. Partially penetrated wells typically experience a larger pressure drop of fluid flow caused by restricted regions, thus increasing the skin factor. A major challenge for engineers when developing completion designs or optimizing skin factor variables is devising and testing suitable partial penetration skin and comparing completion options. Several researchers have studied and calculated a partial penetration skin factor, but some of their results tend to be inaccurate and cause excessive errors. The present work proposes experimental work and a numerical simulation model for accurate estimation of the pseudo-skin factor for partially penetrated wells. The work developed a simple correlation for predicting the partial penetration skin factor for perforated vertical wells. The work also compared the results from available models that are widely accepted by the industry as a basis for gauging the accuracy of the new correlation in estimating the skin factor. Compared to other approaches, the novel correlation performs well by providing estimates for the partial penetration skin factor that are relatively close to those obtained by the tested models. This work's main contribution is the presentation of a novel correlation that simplifies the estimation of the partial penetration skin factor in partially completed vertical wells.

Performance Analysis of Hydrocarbon Wells Based on the Skin Zone

The purpose of this research is to study the area near the bottom of the hydrocarbon well, which is usually affected by drilling and development operations, and to find a modern method that improves the transfer of fluid from the reservoir to the well.The area near the wellbore of an oil and gas formation is a very active and unstable zone. Field studies have shown that during the process of drilling the first well into the pay zone, a new area of disturbed permeability and porosity forms around the wellbore. This disturbed area is called the skin zone and is characterized by different properties. The skin zone can also form during the completion processes of hydrocarbon wells.In terms of well test processing for any hydrocarbon well, the term "skin effect" should be understood as the effect of changes in the lower wellbore zone (i.e., changes in rock properties, changes in formation fluid, formation structure, geologic section, etc.) on bottom wellbore pressure. This indicates a change in the permeability of the bottom zone of the borehole during drilling and development.In this paper, a new computational method is proposed in which the investigation of hydrocarbon well condition can be performed in two ways. The first way represents replacing the true radius of the wellbore (rw) with an effective radius (rwe). Under this condition, the skin factor term reflects only the effect of changes in the bottom wellbore zone. The second way is that the skin factor indicates not only the amount of change in the bottom wellbore zone, but also the effect of hydrodynamic imperfection of the hydrocarbon well performance during production, while maintaining the value of the well radius. After evaluating these parameters, it is possible to conclude the effectiveness of the implemented measures in the bottom wellbore zone of the formation. At the same time, the value of the skin factor after the performed works regarding the impact on the bottom zone can determine the positive or negative impact on the operation of the hydrocarbon well.