A Well Testing Analysis Methodology and Application for Tight Reservoirs

All Shale Gas reservoirs are not the same. There are no typical Tight Gas reservoirs. These two statements can be found numerous times in the literature on shale gas and tight gas reservoirs. The one common aspect of developing these unconventional resources is that wells in both must be ‘hydraulically fractured’ in order to produce commercial amounts of gas. Operator challenges and objectives to be accomplished during each phase of the Asset Life Cycle (Exploration, Appraisal, Development, Production, and Rejuvenation) of both shale gas and tight gas are similar. Drilling, well design, completion methods and hydraulic fracturing are somewhat similar; but formation evaluation, reservoir analysis, and some of the production techniques are quite different. Much of the experience in shale and tight gas has been developed in the US and in Canada, to a lesser extent; and most of the technologies that have been developed by operators and service companies are transferable to other parts of the world. However, the infrastructure, including equipment and service company availability, governmental regulations, logistics, processing, environmental considerations, and pricing are not the same as in the US. This may impact the rate of the technology transfer as well as the selection of some of the technology. This paper is focused on operations challenges, technologies, and experience associated with shale and tight gas projects. It is likely that environmental concerns and the drive to reduce development costs of tight and shale gas reservoirs will drive new approaches to the development of these reservoirs in China, Latin America, Middle East, North Africa, and other parts of the world.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 131786, ’Integration of Microseismic and Other Post-Fracture Surveillance With Production Analysis: A Tight Gas Study,’ by C.R. Clarkson, SPE, University of Calgary, and J.J. Beierle, SPE, Talisman Energy, prepared for the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. The paper has not been peer reviewed. Quantitative production analysis of tight gas reservoirs is a challenge because of complex reservoir characteristics, induced-hydraulic-fracture properties in vertical wells, operational complexities, and data quality. These challenges make extracting reservoir and hydraulic-fracture properties (i.e., fracture half-length, xf, and fracture conductivity) solely from production and flowing-pressure data difficult, often resulting in nonunique answers. Many tight gas reservoirs are exploited with horizontal wells, often stimulated with multiple hydraulic fractures, imparting greater complexity to the analysis. Flow-regime identification, which is critical to correct analysis, becomes more complicated because of the variety of flow regimes that could be encountered in such wells. Introduction Development of tight gas, shale gas, and coalbed methane (collectively referred to as unconventional gas reservoirs) benefits from advances in drilling, completions, and stimulation technology; formation evaluation; and during-/post-stimulation-surveillance technology. Formation-evaluation techniques enable determining critical parameters such as matrix permeability in ultratight rock from cores, and adsorbed- and free-gas content in shale and coalbed methane from cores and cuttings. During-/post-fracture-stimulation-surveillance technology (such as microseismic monitoring) aids identifying the hydraulic-fracture geometry created in unconventional reservoirs (hydraulic-fracture growth), particularly in coals and shales. Predicting hydraulic-fracture geometries is complicated by heterogeneities, such as natural fractures (healed or open) and layering (with associated contrasts in mechanical properties), and in some cases, by nonlinear elastic behavior. Advanced production-analysis techniques, such as production type curves, supplement reservoir and stimulation information obtained from pressure-transient analysis (well testing) in conventional oil and gas reservoirs and even some unconventional reservoirs such as coalbed methane and tight gas. However, applying these methods to tight gas and shale reservoirs that are produced through multifractured horizontal wells has been difficult because of the complexity of the system, poor quality of flowing-pressure and rate data, and the lack of sufficient data to characterize the system fully. Even if the production and flowing-pressure data were of sufficient quality to identify flow regimes, as in pressure-transient analysis, without additional surveillance information, it is difficult to ascertain how the flow regimes relate to the reservoir and hydraulic-fracture system. If the flow regimes are misinterpreted, then the extracted information will be incorrect. A workflow is proposed to improve the quality of information extracted from production-data analysis (PDA) of hydraulically fractured horizontal wells completed in tight gas reservoirs.

Upper Paleozoic total petroleum system and geological model of natural gas enrichment in Ordos Basin, NW China

Unconventional hydrocarbons occupy an enormous proportion in the world energy budget nowadays. Both the progress in exploration and development of them as well as resources assessment results are the major factors to determine the future pattern of the world energy market. Although there are problems and difficulties, opportunities always coexist together with challenges. So far, the evaluation method of shale oil and gas has become matured, while the development of coalbed methane is rapidly driven by both demand and technology. The contribution of tight oil and gas reservoirs is increasingly prominent. For the timebeing, unconventional hydrocarbons in North America is dominated by shale gas and tight reservoirs, and the exploration and development of them are growing rapidly. In the Asia-Pacific region, shale gas projects in China and coalbed methane projects in Australia are developed in full swing and can be considered successful examples. The Europe has also started its ice-breaking travel, eventhough the European environmental and social impacts will greatly restrict local development of shale oil and gas in Europe. Meanwhile, other regions and countries such as Brazil and Argentina in South America are also having hot spots. Although the technology in exploration and development has been gradually optimized and put into practice worldwide, technological levels and geological conditions still vary considerabley in different countries. In particular, many problems such as economic evaluation, ecological environment evaluation, social impact evaluation and standardized operations, urgently need more concerns from various countries all over the world. Among issues that should be paid attention to presently are atmospheric pollution, water scarcity and pollution, wastewater treatment and utilization, possible land subsidence, environmental ecology, and social impacts of local communities.

Unconventional reservoirs, including gas shales and tight gas sands, have gained prominence in the energy sector due to technological advancements and escalating energy demands. The oil industry is eagerly refining techniques to decipher these reservoirs, aiming to reduce data collection costs and uncertainties in reserve estimations. Characteristically, tight reservoirs exhibit low matrix porosity and ultra-low permeability, necessitating artificial stimulation for enhanced production. The efficacy of the stimulation hinges on the organic material distribution, the rock’s mechanical attributes, and the prevailing stress field. Comprehensive petrophysical analysis, integrating standard and specialized logs, core analyses, and dynamic data, is pivotal for a nuanced understanding of these reservoirs. This ensures a reduction in prediction uncertainties, with parameters like shale volume, porosity, and permeability being vital. This article delves into an intricate petrophysical evaluation of the Nene field, a West African unconventional reservoir. It underscores the geological intricacies of the field, the pivotal role of data acquisition, and introduces avant-garde methodologies for depth matching, rock typing, and the estimation of permeability. This research highlights the significance of unconventional reservoir exploration in today’s energy milieu, offering a granular understanding of the Nene field’s geological challenges and proffering a blueprint for analogous future endeavours in unconventional reservoirs.

China is rich in coal-bearing gas resources, but the strata of coalbed methane, shale gas and tight sandstone gas are often stacked together with several layers with one type of gas, two types of gas or even three types of gas. The reservoir conditions are complex with great different physical properties and low permeability, which make exploitation difficult. The multi-layer co-production is often adopted to improve the productivity of a single well. However, different types of gas reservoirs demonstrate different gas production characteristics and different interlayer interference, which brings difficulty in the optimization of gas production in coal-bearing strata. In order to strengthen the analysis of production characteristics and interlayer interference in coal-bearing strata, three two-layer co-production models for coalbed methane, shale gas and tight sandstone gas respectively were established using reservoir numerical simulation method based on the reservoir physical characteristics of coalbed methane, shale gas and tight sandstone gas. A virtual wellbore setting was proposed, and the interference factor was defined to be the ratio of co-production and separate production, which can simulate and characterize the phenomena of interlayer interference of production more reasonably. Then the gas production and interlayer interference in different types of tight gas reservoirs were predicted, analyzed and compared comprehensively. The results show that due to the different occurrence and production mechanisms of coalbed methane, shale gas and tight sandstone gas, in the same coal-bearing strata, the tight sandstone gas has the highest production rate at the beginning of production, but it is easily affected by the interlayer interference induced by the pressure difference between two layers, while the release of the productivity of coalbed methane and shale gas is usually lagged behind. The desorption pressure and water saturation are the sensitive factors for interlayer interference. In addition, the influence of water loading at the bottom of the wellbore on gas production cannot be ignored. The results have a guiding significance to the multi-layer co-production in coal-bearing strata.KeywordsCoal-bearing strataMulti-layer co-productionNumerical simulationProductivity predictionInter-layer interferenceSensitivity analysis

Carbon dioxide is one of the capable processes in improving oil recovery from low-permeable oil reservoirs. However, the evaluation of cyclic $$\text {CO}_{2}$$ injection process with nanopore confinement effect in tight reservoirs is deficient in the oil industry. The nanopores confinement plays a significant role in low-permeable formations, creating a high capillary pressure which substantially influences fluid phase behavior and fluid flow in tight reservoirs. In order to consider the effect of nanopore confinement in unconventional reservoirs, the conventional methods need to be modified. Thus, we evolve an effective model for cyclic $$\text {CO}_{2}$$ injection process considering the effect of complex fracture geometry with nanopore confinement on the production from tight formations. Firstly, the reservoir fluid properties with nanopore confinement are estimated. Secondly, the minimum miscibility pressure is measured and verified with experimental data. Lastly, the well performance of cyclic $$\text {CO}_{2}$$ injection process in unconventional tight reservoirs is evaluated based on few parameters such as $$\text {CO}_{2}$$ diffusivity and matrix permeability. The results show that the combined effect of capillary pressure and $$\text {CO}_{2}$$ dispersion has significantly influenced the oil production efficiency from tight oil reservoirs. The oil recovery factor of cyclic $$\text {CO}_{2}$$ injection process at five years boosts from 14.67% as primary recovery to 22.54% due to $$\text {CO}_{2}$$ molecular diffusion effect with overall 7.87% incremental recovery. Moreover, the incremental oil recovery of cyclic $$\text {CO}_{2}$$ injection process is increased further by 1.7% while taking into consideration the combine effect of capillary pressure and $$\text {CO}_{2}$$ diffusion on the oil recovery. This study provides an appropriate method for predicting the production of cyclic $$\text {CO}_{2}$$ injection process with a complex fracture geometry, considering the capillary pressure and $$\text {CO}_{2}$$ diffusion on well performance of tight oil reservoirs.

Many operators do not routinely run pre-stimulation pressure buildup tests in low permeability gas reservoirs. Frequently, all that is available is a single-rate flow test. To obtain permeability estimates for FERC filings and to evaluate the reservoir, a new method has been developed for analyzing typical pre-fracture production data. Permeability estimates obtained from this method have been used as a major source of data in numerous successful tight gas determinations, including the Cotton Valley, Wilcox Lobo, and Canyon formations in Texas. The paper shows that this simple method can be quite reliable. This conclusion is based on a comparison of permeabilities estimated with this technique and with more rigorous determinations from pressure buildup tests.

The tremendous efforts have been made by the industry in tapping the recoverable resources from the unconventional reservoirs in the past ten years. Shale (tight) gas and shale (tight) oil are the two typical ones. Some research studies focused on the effect of porous media on the dew point of gas condensates in terms of experimental and theoretical work. The contradictory conclusions were reached. On the other hand, some conclusions were made for crude oil as well on the basis of the measurements of the bubble point pressure of crude oil in porous media. Therefore, it is of great importance to develop an effective method to predict the phase behavior of shale gas and shale oil in porous media and investigate the effects of some factors on the saturation pressures of gas condensate and crude oil in tight reservoirs. In this paper, a general framework of theoretical models has been developed to predict the saturation pressures of shale gas and shale oil in tight reservoirs. The Laplace equation is used to relate to the pressures in vapor and liquid phases from the curved interface. The Parachor model is applied to determine the interfacial tensions of crude oil and gas condensate. By taking into account of porous media in the proposed models, the calculations have been performed in some case studies. The effect tendency of some properties of porous media such as permeability and porosity on the dew or bubble point of reservoir fluid is discussed in this paper.

Summary Unconventional resources are important for exploration and production in Mexico. The Formation Chicontepec is considered unconventional tight oil & gas reservoirs. The tight reservoirs (TR) are called like that for their low permeability and porosity by petroleum and petrophysical field. This paper provide a research about concepts, classification, physical properties and petrophysical characteristics of TR, Identification of TR with cores and well logs, geological occurrence and sedimentary characteristics of unconventional tight reservoir in Mexico. Tight oil must not be confused with shale oil & gas, because they varied through API gravity, viscosity of fluids, extraction method and other aspects. Reservoirs connectivity is a modifying attribute, usually limited and discontinuous; for these reason, the stratigraphic correlation is discontinuous, because its heterogeneity. The Production cost is closed to economic limit and sometimes is overtaked. Well electrical logs are limited by their vertical resolution in these reservoirs; the only exception is the micro-resistivity image log. In future studies, is appropriated use equations and inversion models of well logs focus on TR.

Molecular diffusion is a transport mechanism often ignored in conventional, non-fractured multi-component petroleum upstream simulations due to the predominance of convection. In unconventional fractured reservoirs, diffusion plays a vital role in hydrocarbon production. A "shale" reservoir is characterized by thin, ultra-tight matrix blocks surrounded by natural or induced fractures. This creates conditions in which diffusion fluxes could be significant. In ultra-tight formations, convection is a slow process, and the presence of thin blocks surrounded by fractures increases the contact area, both of which favors diffusion. In this paper, we discuss the application of cyclic gas injection to enhance recovery in tight reservoirs in the gas condensate window. A fully implicit model is implemented with the objective to investigate the impact of diffusion on liquid dropout and vaporization on a matrix level. Diffusion fluxes are implemented considering a gradient in total chemical potential as driving force. Additionally, since capillary forces are significant in ultra-tight formations, phase equilibria calculations are modified to account for nano-confinement effects. Sensitivity is performed on matrix block size and injection gas composition (pure C1, a mixture of C1 and CO2, and a mixture of C1, C2 and C3), and the role of diffusion is evaluated for each scenario. As gas is injected, the composition of heavier hydrocarbon fractions in the gas phase significantly increases due to vaporization of condensate. Molecular diffusion helps to spread composition banks. As a result, liquid dropout is delayed during the subsequent production stages. Heavier fractions remain in the gas phase for longer periods, which ultimately enhances its recovery. In addition to that, retention of heavier fractions due to condensate dropout is intensified as the size of the matrix block increases. Longer matrix blocks result in lower swept length for the same number of cycles. As a result, liquid dropout occurs earlier because feed of gas at in-situ composition diffuses from the center of the matrix block towards the fracture boundary. We demonstrate that heavier components recovery is more affected by molecular diffusion than lighter components. Furthermore, it is observed that molecular diffusion strongly influences time and location of occurrence of liquid dropout in tight gas condensate reservoirs. Implementation of a rigorous model that includes convection, diffusion, adsorption and phase change allowed to investigate the commingling effects of different physics involved in enhanced recovery in unconventional reservoirs.

Accurate estimation of gas-in-place is crucial for successful evaluation and exploitation of unconventional gas reservoirs, such as shale gas, coalbed methane, and tight gas. However, gas effective porosity, one of the most important parameter in estimating gas in-place, is commonly measured on crushed samples of cores or cuttings at ambient pressure although many studies have shown that the porosity and permeability of reservoirs rocks decrease with increasing effective stress, and thus the pore volume/porosity measured on crushed samples at ambient (zero stress) conditions will be larger than porosity measured under in-situ reservoir stress conditions. Normally the stress-dependence of porosity is simply accounted for by a correction factor based on the linear poro-elastic deformation, which is likely an over-simplification. In present study, we developed a new protocol for simultaneously measuring stress-dependent In-Situ Permeability and Porosity (ISPP) that provides a method for routine characterization of effective porosity and permeability under simulated reservoir conditions. Our new method can significantly reduce the uncertainties of porosity introduced by testing crushed samples under ambient conditions, testing time, and the need for good quality core samples that are usually unavailable. Preliminary test results indicate that the stress dependence of porosity (or pore compressibility) of fine grained reservoir rocks follows a unique trend of each tested sample, which cannot be simply adjusted from ambient porosity by a universal factor. Physical and numerical sample tests suggest that our ISPP method can obtain permeability similar to the normal pressure Pulse-Decay Permeability (PDP) technique if samples are homogeneous or transversely layered along their axes. Otherwise, our ISPP method likely tests the geometrical average permeability of longitudinally layered samples instead of the weighted arithmetical average permeability tested by the PDP method. Overall, our approach of simultaneously measuring effective porosity and permeability under reservoir conditions offers intrinsically consistent porosity-permeability data to characterize unconventional reservoirs. Our study also reveals that utilization of different methods to test samples in different orientations and different sizes is necessary to rigorously characterize the hierarchical permeability and porosity of heterogeneous and microporous unconventional reservoir rocks.

Due to low permeability of tight gas shale, production at commercial level requires conducting effective hydraulic fracturing and applying horizontal drilling technologies. Therefore, successful production from such complex reservoirs is heavily dependent on the selection of an appropriate completion technology requiring sufficient knowledge of borehole shape. Borehole breakouts provide valuable information for evaluation of in-situ stresses and verification of geomechanical models. Caliper and image logs, the regularly used methods to identify breakout zones, have several limitations such as not having a full coverage of the borehole wall, being affected by different parameters, pad width limitation, low resolution, and complicated processing procedure. In addition, good quality image logs are not usually available for shaly formations because of the requirement of using oil-based mud. This paper discusses a new approach to identify borehole breakouts in tight gas shale using some petrophysical logs. The used approach employs number of data processing techniques to determine borehole intervals with maximum likelihood of enlargement. The applicability and the generalization capability of the approach were supported by having significant accuracy. Case study on Burnett shale is presented in this paper. Introduction Tight gas, coal bed methane and gas hydrate are considered as unconventional sources of gas. These unconventional reservoirs have insufficient permeabilityand difficult accessability. Nowadays with decline of production of conventional reservoirs and increase in demand of hydrocarbon fuels, production from unconventional gas reservoir is becoming economic and has been brought into the forefront of energy future. This unconventional energy source is a fast-growing market and is recognised as a huge future potential for production. Economic production of gas from shale gas reservoir is a big challenge for the industry. Due to low permeability of shale, production in commercial quantities requires effective and economic hydraulic fracturing and horizontal drilling technologies. Therefore, having a good understanding of shale mechanical and chemical properties and the state of stresses in the earth's crust (i.e., geomechanical model) is one of the most critical steps toward reservoir evaluation and ultimately development of this sort of resources. In addition, production from such a complex formation with a typical poorly-defined gas-water contacts, natural fractures, and very low matrix permeability, is heavily dependent on the selection of appropriate completion technology (Jacobi, Gladkikh et al. 2008). Consequently, having sufficient knowledge of borehole shape (enlargement zones) is the key point toward a successful production. The integrity of the wellbore plays an important role in petroleum operations including drilling, completion and production. Wellbore failure occurs principally through changes in the original stress state due to drilling the rock that concentrates stresses around a wellbore. If the new stresses exceed the rock strength then breakouts form around the borehole. Breakouts are valuable information to estimate the magnitude and orientation of earth stresses and to calibrate and validatethe geomechanical model. In addition, they provide final borehole shape which is a critical factor in completion and production optimization. This study aims to identify borehole enlargement zones in gas shale formations from common petrophysical logs using some data processing techniques such as Bayesian classification, wavelet signal decomposition and data fusion instead of caliper and image logs that are associated with many limitations.

Estimation of reserves in tight gas and shale gas reservoirs is problematic due to the low to ultra-low permeability characteristics of these reservoir systems. The sole application of conventional decline curve analysis methodologies often yields erroneous reserve estimates. Therefore, the use of theoretically-based production analysis techniques has become a must to analyze well performance and estimate reserves. The primary objective of this work is to develop a systematic workflow, which integrates model-based production analysis and rate-time relations, for the analysis/interpretation of well performance data in unconventional reservoirs. The major steps in the proposed workflow are:Diagnosis of production data.Construction of a base well/reservoir model utilizing static well/reservoir data as well as completion/stimulation parameters.Extrapolation of the model to predict well performance along with the use of rate-time decline relations. The proposed methodology is demonstrated using data from unconventional reservoirs, including a horizontal well with multiple fractures. We present the application of rate-time relations to provide estimates of time-dependent reserves. The use of βq,cp-derivative is also illustrated in distinguishing data characteristics as well as identifying issues associated with data.

Dense arrays of surface drifters are used to quantify the flow field on time and space scales over which high-frequency (HF) radar observations are measured. Up to 13 drifters were repetitively deployed off the Santa Barbara and San Diego coasts on 7 days during 18 months. Each day a regularly spaced grid overlaid on a 1-km2 (San Diego) or 4-km2 (Santa Barbara) square, located where HF radar radial data are nearly orthogonal, was seeded with drifters. As drifters moved from the square, they were retrieved and replaced to maintain a spatially uniform distribution of observations within the sampling area during the day. This sampling scheme resulted in up to 56 velocity observations distributed over the time (1 h) and space (1 and 4 km2) scales implicit in typical surface current maps from HF radar. Root-mean-square (RMS) differences between HF radar radial velocities obtained using measured antenna patterns, and average drifter velocities, are mostly 3–5 cm s−1. Smaller RMS differences compared with past validation studies that employ current meters are due to drifter resolution of subgrid-scale velocity variance included in time and space average HF radar fields. Roughly 5 cm s−1 can be attributed to sampling on disparate time and space scales. Despite generally good agreement, differences can change dramatically with time. In one instance, the difference increases from near zero to more than 20 cm s−1 within 2 h. The RMS difference and bias (mean absolute difference) for that day exceed 7 and 12 cm s−1, respectively.