Reservoir Stimulation Techniques Research Articles

An integrated approach to unconventional resource play reservoir characterization, Thistleton-1 case study, NW England

Scott Brindle, David O’Connor, Richard Windmill, Peter Wellsbury, Guy Oliver, Graham Spence and Chi V. Ly characterize a UK unconventional reservoir using integrated AM and TOC data to constrain and improve the accuracy of petrophysical modelling. In the past, the oil and gas industry considered hydrocarbon resources locked in tight, impermeable formations like shale uneconomical to produce. However, advances in well steering, drilling and reservoir stimulation techniques have dramatically changed this perspective. Unconventional shale reservoirs have low permeability and cannot produce economically without effective placement of horizontal laterals and effective hydraulic stimulation. To achieve this, it is critical to recognize brittle units responsive to hydraulic fracturing and rich in organic matter. Shale mineralogy impacts the effectiveness of stimulation. Heterogeneity in shale reservoirs expressed by mineral composition, richness of organic matter and brittleness significantly influences shale gas production. In these reservoirs, the occurrence of clays is a significant risk to production and it is a major challenge to be able to locate and quantify them. The industry reported $7bn of unnecessary costs due to unconventional wells not reaching their production targets (Welling and Company, 2012). Moreover, 15-20% of all fracture stages are reported as ineffective while 35-40% of perforation clusters do not contribute to production (Hodenfield, 2012) highlighting a need for more low-cost and low-risk data. This data could help to improve completion designs to achieve more consistent production from all stages and increase the overall profitability.

Reservoir stimulation techniques to minimize skin factor of Longwangmiao Fm gas reservoirs in the Sichuan Basin

The Lower Cambrian Longwangmiao Fm carbonatite gas reservoirs in the Leshan-Longnüsi Paleouplift in the Sichuan Basin feature strong heterogeneity, well-developed fractures and caverns, and a high content of H2S, so these reservoirs are prone to reservoir damages caused by the invasion of drilling fluid or the improper well completion, so to minimize the reservoir skin factor is key to achieving high yield of oil and gas in this study area. Therefore, based on the geological characteristics of the Longwangmiao reservoirs, the binomial productivity equation was applied to demonstrate the possibility and scientificity of minimizing the skin factor. According to the current status of reservoir stimulation, the overall skin factors of reservoir damage caused by drilling fluid invasion, improper drilling and completion modes etc were analyzed, which shows there is still potential for skin factor reduction. Analysis of reservoir damage factors indicates that the main skin factor of Longwangmiao Fm reservoirs consists of that caused by drilling fluid and by improper completion modes. Along with the minimization of skin factor caused by drilling and improper completion, a fracture-network acidizing process to achieve “non-radial & network-fracture” plug-removal by making good use of natural fractures was proposed according to the characteristics of Longwangmiao Fm carbonatite reservoirs.

Improved Conductivity and Proppant Applications in the Bakken Formation

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163849, ’Investigation of Improved Conductivity and Proppant Applications in the Bakken Formation,’ by Bethany Kurz, SPE, Energy and Environmental Research Center, Darren Schmidt, SPE, and Phil Cortese, SPE, Weatherford, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed. Production from the Bakken and Three Forks formations within the Williston basin is continuing to climb as a result of applied horizontal drilling and hydraulic fracturing. Key to increased oil production is the evolution of reservoir-stimulation techniques, such as fracturing-fluid systems and proppant types. This study evaluated the key factors that may result in conductivity loss within the Bakken and Three Forks reservoirs. The results of this work suggest that certain fluids may affect both rock and proppant strength and, therefore, require consideration. Introduction This work was conducted in an effort to answer questions regarding reservoir stimulation in the Bakken petroleum system, specifically with respect to conductivity loss in hydraulic fractures over time. The key questions that were evaluated include Can conductivity loss be attributed to proppant degradation, rock strength, or both? What role do fluids have in affecting propped-fracture conductivity? To what extent does fluid exposure affect the degradation of rock strength and proppant performance? How do various proppants perform relative to one another under stress using actual core samples from the Bakken petroleum system? Laboratory tests were conducted to evaluate the sensitivity of Bakken and Three Forks formation cores to various fluids; to evaluate the strength of Ottawa sand, an unspecified premium precured resin-coated sand (RCS), and a lightweight ceramic proppant (Econoprop) with respect to various fluids; and to measure the relative laboratory conductivity performance of propped fractures using actual rock core. Fluids used in experiments to examine potential strength degradation for both rock and proppant included the following: Slickwater—a mixture of polyacrylamide and fresh water Crosslinked gel—guar-polymer thickening agent, borate crosslinker, and fresh water Gelled diesel—diesel fuel and phosphate ester Bakken-formation crude—crude oil Bakken-formation brine—highly concentrated saltwater The fluids were selected on the basis of the most common fluids expected to be encountered in the Bakken formation. Embedment Brinell-hardness-index testing is a measure of rock strength that is determined by embedding a metal ball into formation rock at a given applied load. This type of index testing was used to gauge the relative strength of Bakken and Three Forks samples before and after exposure to formation and hydraulic-fracturing fluids. Core samples used to study rock strength originated from the North Dakota Industrial Commission (NDIC) #16771 well, located in the Manitou field of Mountrail County. Rock strength was measured with a Brinell-hardness-test apparatus. Publicly available hardness data were available from two wells in proximity, including NDIC #15986, Robinson Lake field, Mountrail County, approximately 10 miles to the southeast NDIC #16083, Capa field, Williams County, approximately 10 miles to the southwest

Corrosion Inhibition of Tubing Steel during Acidization of Oil and Gas Wells

Acidization is an oil reservoir stimulation technique for increasing oil well productivity. Hydrochloric acid is used in oil and gas production to stimulate the formation. The acid treatment occurs through N80 steel tubes. The process requires a high degree of corrosion inhibition of tubing material (N80 steel). In the present investigation effect of synthesized amino acid compounds, namely, acetamidoleucine (AAL) and benzamidoleucine (BAL) as corrosion inhibitors for N80 steel in 15% HCl solution was studied by polarization, AC impedance (EIS), and weight loss measurements. It was found that both the inhibitors were effective inhibitors and their inhibition efficiency was significantly increased with increasing concentration of inhibitors. Polarization curves revealed that the studied inhibitors represent mixed type inhibitors. AC impedance studies revealed that charge transfer resistance increases and double layer capacitance decreases in presence of inhibitors. Adsorption of inhibitors at the surface of N80 steel was found to obey Langmuir isotherm.

Modelling of transport of two proppant‐laden immiscible power‐law fluids through an expanding fracture

AbstractHydraulic fracturing technology is one of the most popular and efficient reservoir stimulation techniques in oil and gas industry since it allows significant increase of the hydrocarbon production rate. A possible advancement of this technology involves consequent pumping of several immiscible fluids laden with solid particles (proppant) into a fracture. This technique has a potential for better control of the proppant placement and, thus, a better control of the fracture shape. The major result of the present work is a mathematical model and a computational code for investigation of a flow of two immiscible slurries inside an expanding fracture. © 2012 Canadian Society for Chemical Engineering

Corrosion inhibition of Tubing steel during acidization of oil and gas wells

Acidization is an oil reservoir stimulation technique for increasing well productivity. Hydrochloric acid, HCl, is used in oil and gas production to stimulate the formation. The acid treatment occurs through steel tubes. The process requires a high degree of corrosion inhibition. The present study deals with the evaluation of the effectiveness of the new synthesized compound namely; 6-methyl-5-[ m-nitro styryl]-3-mercapto-1,2,4-triazine as corrosion inhibitor for mild steel in 12% HCl solution at 50 °C using various chemical and electrochemical techniques. The results showed that anodic dissolution of mild steel was remarkably decreased. The strong adsorption ability of this new synthesized compound can be attributed to the presence of multiple adsorption centers of nitrogen as well as π-donor moieties.

Methodology to Predict the Initiation of Multiple Transverse Fractures from Horizontal Wellbores

Abstract Multi-stage, transversely fractured horizontal wellbores have the potential to greatly increase production from low permeability formations. Such completions are, however, susceptible to problems associated with near-wellbore tortuosity, particularly multiple fracturing from the same perforated interval. A criterion, based on that by Drucker and Prager, has been derived, which predicts the wellbore pressures required to initiate secondary multiple transverse hydraulic fractures in close proximity to primary fractures. Secondary fracture initiation pressures predicted by this new criterion compare reasonably well with those measured during a series of unique laboratory-scale multiple hydraulic fracture interaction tests. Both the multiple fracture initiation criterion and the laboratory results suggest that close proximity of primary hydraulic fractures increases the initiation pressures of secondary multiple fractures by the order of only 14%. This demonstrates that transversely fractured horizontal wellbores have limited capacities to resist the initiation of multiple fractures from adjacent perforations or intersecting heterogeneities. Petroleum engineers can use the multiple fracture initiation criterion when designing hydraulic fracture treatments to establish injection pressure limits, above which additional multiple fractures will initiate and propagate from the wellbore. Introduction A significant proportion of the worldwide recoverable hydrocarbon resource exists in reservoirs possessing permeabilities of less than one milli-Darcy (mD). At present, low production rates accompanying such poor permeabilities imply that, if hydrocarbons are to be exploited economically, some form of permeability enhancement or stimulation must be carried out within these reservoirs. Even where initial permeabilities are relatively high, stimulation may still be required to overcome problems associated with localised permeability damage due to, for example, drilling mud invasion. Matrix acidisation and hydraulic fracturing remain the principal reservoir stimulation techniques. The advantages of horizontal wells in comparison with vertical wells have been extensively documented. Indeed, in an increasing number of fields throughout the world, the production of hydrocarbons is performed exclusively through horizontal wells. Whilst still a relatively rare form of completion, fractured horizontal wells are becoming more common in low permeability formations. This is particularly so where surface geographies dictate that wells must deviate from central drill pads, such as in offshore or arctic regions. Hydraulic fractures, regardless of their origin, always attempt to propagate in planes orthogonal to the minimum horizontal stress, in what is commonly referred to as the "preferred fracture plane." However, while hydraulic fracture propagation planes are fixed, the horizontal wellbores from which they emanate may assume completely arbitrary orientations. Two limiting wellborefracture configurations are the focus of much attention:"Longitudinal Fractures" propagate in planes parallel with wellbore axes, as illustrated in Figure 1. They form where horizontal wells are drilled parallel with the larger of the horizontal stresses (or parallel with the preferred fracture plane);"Transverse Fractures" propagate in planes orthogonal to wellbore axes, as illustrated in Figure 2. They form where horizontal wells are drilled perpendicular to the larger of the horizontal stresses (or perpendicular to the preferred fracture plane). A number of studies have been carried out, comparing the production character

Tests of the Stability and Time-Step Sensitivity of Semi-Implicit Reservoir Stimulation Techniques

Abstract A reservoir simulation technique that employs semi-implicit approximations to relative permeabilities exhibits excellent stability and permeabilities exhibits excellent stability and convergence characteristics when applied to water- or gas-coning problems. Recent workers in this area have made a simplifying assumption in order to linearize the flow terms of the semi-implicit finite-difference equations. This paper describes a method of solving efficiently paper describes a method of solving efficiently the nonlinear form of the equations and demonstrates that time-step sensitivity is reduced by iterating on the nonlinear terms. In addition, it addresses the problem of allocating a well's production among multiple grid blocks. Example problems include both water-coning and gas-percolation applications. Introduction Multiphase reservoir simulators traditionally have employed finite-difference approximations in which relative permeabilities are evaluated explicitly at the beginning of each time step. Simulators of this type are capable of handling many reservoir studies in a perfectly satisfactory fashion, but they are incapable of solving economically problems characterized by high flow velocities. Included in this category are the studies of such phenomena as well coning and gas percolation. The difficulty in such problems is a stability limitation imposed by the use of explicit relative permeabilities. In an attempt to overcome this permeabilities. In an attempt to overcome this limitation, Blair and Weinaug developed a simulator that employed implicitly evaluated relative permeabilities. The increased stability of their permeabilities. The increased stability of their equations allowed the use of time steps much larger than previously possible, but this was counteracted by an increase in the computational work per time step and an increased difficulty in the iterative solution of the difference equations. While the net result was a significant advance in the solution of coning problems, improvements still were needed to increase the dependability and decrease the cost of obtaining solutions for such problems. More recently, two papers were published describing a method that employs semi-implicit relative permeabilities. This method is greatly superior to the fully implicit method, both in computational effort and maximum time-step size. In developing this method, the previous workers made a simplifying assumption to obtain linear finite-difference equations. We have developed a reservoir simulator based on the nonlinear form of the semi-implicit finite-difference equations. This paper describes the techniques used in the simulator and presents the results of some tests conducted with it. These include time-step sensitivity studies and tests of alternate production allocation methods. Some of these tests compare the nonlinear form of the semi-implicit method with the linear form. SPEJ P. 253