Experimental Study on Shut-in-Time Optimization for Multi-Fractured Horizontal Wells in Shale Reservoirs

The optimization of shut-in-time in shale gas well is an important factor affecting the production of single well after volume fracturing. In this study, a new method for determining the optimal shut-in-time considering clay mineral content and ion diffusion concentration was proposed. First, a novel water spontaneous imbibition apparatus under the conditions of formation temperature and confining pressure was designed. Then, the water imbibition satuation of 15 shale samples from the Longmaxi Formation (LF) of the Sichuan Basin were measured to quantitatively evaluate the water imbibition ability and classify reservoir types. Finally, the salt ion concentration diffusion experiment was carried out to optimize the shut-in-time of different types of shale reservoirs. The experimental results shown that the clay mineral content was the key factor affecting water wettability of shale, the shale reservoirs can be divided into two types and the critical value of clay mineral content was about 40%. Based on the law of salt ion diffusion in shale, the initiation time of micro-fractures induced by shale hydration was about 10-15 days. Under the experimental conditions, the optimal shut-in time of type I shale reservoir and type II shale reservoir were about 20 days and 15 days respectively. The average daily gas production has increased from 15.6×104 m3/day to 25.1×104 m3/day. The study results can provide scientific basis for the optimization of flowback regime of shale gas resrvoirs.

Achieving Productivity and Clean Inflow from an Unconventional Reservoir in North Kuwait

Jurassic Kerogen shale/carbonate reservoir in North Kuwait provides the same challenges as North American shales in addition to ones not yet comparable to any other analogue reservoir globally. It is the Kerogen's resource density; however, that makes this play so attractive. Like ‘conventional’ unconventional in the US and Canada this kerogen is believed to be a source rock and is on the order of micro-to nano-Darcy permeability. As such, industry learnings show that likely long horizontal laterals with multiple hydraulic fractures will be necessary to make commercial wells. Following this premise, the immediate objective is to establish clean inflow into wellbore as the previous attempts to appraise failed due to "creep" of particulate material and formation flowing into the wellbore. Achieving this milestone will confirm that this formation is capable of solids free inflow and will open a new era in unconventional in Kuwait. Planning for success, the secondary objective is to then upscale to full field development. The main uncertainties lie in both producibility and ‘frac-ability’, and certainly, these challenges are not trivial. A fully integrated testing program was applied to both better understand the rock mechanical properties and to land on an effective frac design. Scratch, unconfined stress, proppant embedment and fluid compatibility tests were conducted on full core samples for geo-mechanics to prepare a suite of strength measurements ahead of frac design and to custom-design the fracture treatment and "controlled" flowback programs to establish inflow from Kerogen without "creep". Unlike developed shale reservoirs, the Jurassic Kerogen tends to become unconsolidated when treated. The pre-frac geomechanics tests will be outlined in this paper with the primary objective of finding the most competent reservoir unit to select the limited perforation interval to frac through so that formation competency can be maintained. Previous attempts failed to maintain a competent rock matrix even only after pumping data-fracs. Acidizing treatments also turn the treated rock volume into sludgy material with no in-situ stability nor ability to deliver "clean inflow". A propped fracturing treatment with resin-coated bauxite was successfully placed in December 2019 in a vertical appraisal well perforated over 6 ft at 12 spf shot density. "Controlled" flowback carried out in January 2020 achieved the strategically critical "clean inflow" with reservoir fluids established to surface. Special proppant technologies provided by an industry leading manufacturer overcame the embedment effects and to control solids flowback. A properly designed choke schedule to balance unloading with a delicate enough drawdown to avoid formation failure was executed. Local oilfields relied on the vast reserves and produced easily from carbonate reservoirs that required only perforating or acid squeezes to easily meet or exceed high production expectations. This unconventional undertaking in Kuwait presents a real challenge as it is a complete departure from the ways of working yet it points towards a very high upside potential should the appraisal campaign can be completed effectively.

Effect of reservoir pressure and total organic content on adsorbed gas production in shale reservoirs: a numerical modelling study

Adsorbed gas plays a key role in organic-rich shale gas production due to its potential to contribute up to 60% of the total gas production. The amount of gas potentially adsorbed on organic-rich shale is controlled by thermal maturity, total organic content (TOC), and reservoir pressure. Whilst those factors have been extensively studied in literature, the factors governing desorption behaviour have not been elucidated, presenting a substantial impediment in managing and predicting the performance of shale gas reservoirs. Therefore, in this paper, a simulation study was carried out to examine the effect of reservoir depth and TOC on the contribution of adsorbed gas to shale gas production. The multi-porosity and multi-permeability model, hydraulic fractures, and local grid refinements were incorporated in the numerical modelling to simulate gas storage and transient behaviour within matrix and fracture regions. The model was then calibrated using core data analysis from literature for Barnett shales. Sensitivity analysis was performed on a range of reservoir depth and TOC to quantify and investigate the contribution of adsorbed gas to total gas production. The simulation results show the contribution of adsorbed gas to shale gas production decreases with increasing reservoir depth regardless of TOC. In contrast, the contribution increases with increasing TOC. However, the impact of TOC on the contribution of adsorbed gas production becomes minor with increasing reservoir depth (pressure). Moreover, the results suggest that adsorbed gas may contribute up to 26% of the total gas production in shallow (below 4,000 feet) shale plays. These study findings highlight the importance of Langmuir isothermal behaviour in shallow shale plays and enhance understanding of desorption behaviour in shale reservoirs; they offer significant contributions to reaching the target of net-zero CO2 emissions for energy transitions by exhibiting insights in the application of enhanced shale gas recovery and CO2 sequestration — in particular, the simulation results suggest that CO2 injection into shallow shale reservoirs rich in TOC, would give a much better performance to unlock the adsorbed gas and sequestrate CO2 compared to deep shales.

Ensemble Learning for Predicting TOC from Well-Logs of the Unconventional Goldwyer Shale

Precise estimation of total organic carbon (TOC) is extremely important for the successful characterization of an unconventional shale reservoir. Indirect traditional continuous TOC prediction methods from well-logs fail to provide accurate TOC in complex and heterogeneous shale reservoirs. A workflow is proposed to predict a continuous TOC profile from well-logs through various ensemble learning regression models in the Goldwyer shale formation of the Canning Basin, WA. A total of 283 TOC data points from ten wells is available from the Rock-Eval analysis of the core specimen where each sample point contains three to five petrophysical logs. The core TOC varies largely, ranging from 0.16 wt % to 4.47 wt % with an average of 1.20 wt %. In addition to the conventional MLR method, four supervised machine learning methods, i.e., ANN, RF, SVM, and GB are trained, validated, and tested for continuous TOC prediction using the ensemble learning approach. To ensure robust TOC prediction, an aggregated model predictor is designed by combining the four ensemble-based models. The model achieved estimation accuracy with R2 value of 87%. Careful data preparation and feature selection, reconstruction of corrupted or missing logs, and the ensemble learning implementation and optimization have improved TOC prediction accuracy significantly compared to a single model approach.

Simulation of tectonic stress field and prediction of fracture distribution in shale reservoir

In this paper, a finite element-based fracture prediction method for shale reservoirs was proposed using geostress field simulations, uniaxial and triaxial compression deformation tests, and acoustic emission geostress tests. Given the characteristics of tensile and shear fractures mainly developed in organic-rich shales, Griffith and Coulomb – Mohr criteria were used to calculate shale reservoirs' tensile and shear fracture rates. Furthermore, the total fracture rate of shale reservoirs was calculated based on the ratio of tension and shear fractures to the total number of fractures. This method has been effectively applied in predicting fracture distribution in the Lower Silurian Longmaxi Formation shale reservoir in southeastern Chongqing, China. This method provides a new way for shale gas sweet spot optimization. The simulation results have a significant reference value for the design of shale gas horizontal wells and fracturing reconstruction programs.

Forecasting the operation of wells in the Bazhenov formation based on a modified dynamic material balance model

Background. Predicting the dynamics of the Bazhenov formation is an important task. Traditionally, it is carried out using geological and hydrodynamic modeling, i. e., solving the direct problem of hydrodynamics. However, for shale reservoirs, this approach is not possible, oil production is a derivative of geology to a lesser extent than technology. Industrial net production rates can be obtained from non-reservoirs in the usual sense. The system of technogenic fractures forms a reservoir associated with oil-saturated rock and the properties of such a system are described by too many parameters with high uncertainty and a number of assumptions [3–7]. On the other hand, there are forecasting methods based on solving the inverse problem of hydrodynamics. Having a sufficient amount of development data, it is possible to predict the dynamics of work based on statistical dependencies [9] or proxy material balance models. The purpose of this work. The purpose of this work was to create a convenient methodology for calculating oil production from the reservoirs of the Bazhenov formation. Methodology. The paper proposes and tests a method for predicting the dynamics of oil, liquid and gas production for wells in the Bazhenov formation based on a modification of the CRM dynamic material balance model (Capacity-Resistive Models — volume-resistive model). Results. The method was tested when calculating the technological indicators of development for the object of one of the fields located in the KhMAO and showed its efficiency, which allows us to recommend it as a basis for drawing up project documents as an alternative to building a hydrodynamic model (GDM).

Evolutions of Oil Generation and Expulsion of Marine-Terrestrial Transitional Shales: Implications From a Pyrolysis Experiment on Water-Saturated Shale Plunger Samples

Shale reservoirs are characterized by self-generation and self-accumulation, and the oil generation and expulsion evolution model of organic-rich shales is one of important factors that obviously influence the enrichment and accumulation of shale oil and gas resources. At present, however, relevant studies on marine-terrestrial transitional shales are inadequate. In this study, a pyrolysis experiment was performed on water-saturated marine-terrestrial transitional shale plunger samples with type Ⅱb kerogen to simulate the evolutions of oil generation and expulsion. The results indicate that marine-terrestrial transitional shales have wider maturity ranges of oil generation and expulsion than marine and lacustrine shales, and the main stages of oil expulsion are later than those of oil generation, with corresponding Ro values of 0.85%–1.15% and 0.70%–0.95%, respectively. Although the oil generation and expulsion process induced a fractionation in compositions between the expelled and retained oils, both the expelled and retained oils of marine-terrestrial transitional shales are dominated by heavy compositions (resins and asphaltenes), which significantly differs from those of marine and lacustrine shales. The kerogen of marine-terrestrial transitional shales initially depolymerized to transitional asphaltenes, which further cracked into hydrocarbons, and the weak swelling effects of the kerogen promoted oil expulsions. The oil generation and expulsion evolutions of these shales are largely determined by their organic sources of terrigenous higher organisms. This study provides a preliminary theoretical basis to reveal the enrichment mechanism of marine-terrestrial transitional shale oil and gas resources.