Shale gas is becoming increasingly important globally. The nature of these reservoirs pose special considerations in reserves estimation. What follows was written in 2001 and needs to be updated based on current experience. Nonetheless, some of the considerations mentioned remain appropriate. As reported in mid-2000, natural gas produced from shale in the US has grown to be approximately 1.6% (0.3 Tcf annually) of total gas production.
The amount of trapped oil in hydrocarbon rich shale reservoirs recoverable through Enhanced Oil Recovery methods such as low salinity water flooding has been an ongoing investigation in the oil and gas industry. Reservoir shales typically have relatively lower amounts of swelling clays and in theory, can be exposed to a higher chemical potential difference between the native and injected fluid salinity before detrimental permeability reduction is experienced through the volumetric expansion of swelling clays. This fluid flux into the pore spaces of the rock matrix acting as a semi permeable membrane is significant enough to promote additional recovery from the extremely low permeability rock. The main goal of this paper is to determine how osmosis pressure build up within the matrix affects geomechanical behavior and hydrocarbon fluid flow. In this study we investigate Pierre shale samples with trace amount of organic content and high clay content as an initial step to fully understanding how the presence of organic content affects the membrane efficiency for EOR applications in shales using low salinity fluid injection. The same concept is also valid when slickwater is utilized as fracturing fluid as majority of the shale reservoirs contain very high salinity native reservoir fluid that will create large salinity contrast to the injected slickwater salinity.
The organic-rich reservoir shales typically have a TOC content of approximately 5 wt% or higher with TOC occupying part of the bulk matrix otherwise to be filled up by clays and other minerals. With less clay within the rock structure, the amount of associated clay swelling arising from rock fluid interaction will be limited. The overall drive of water into the matrix brings added stress to the pore fluid known as osmotic pressure acting on the matrix that also creates an imbalance in the stress state. The native formation fluid with salinity of 60,000 ppm NaCl has been used while 1,000 ppm NaCl brine is utilized to simulate the low salinity injection fluid under triaxial stress conditions in this phase of the study reported here. A strong correlation is obtained between the osmotic efficiency and effective stress exerted on the shale formation. The triaxial tests conducted in pursuit of simulating stress alteration under the osmotic pressure conditions and elevated pore pressure penetration tests indicated that the occurrence of swelling directly impact the formation permeability. These structural changes observed in our experimental results are comparable to field case studies.
Gas production from shale formations is growing, especially in the USA. However, the origin of shale gases remains poorly understood. The objective of this study is to interpret the origin of shale gases from around the world using recently revised gas genetic diagrams. We collected a large dataset of gas samples recovered from shale formations around the world and interpreted the origin of shale gases using recently revised gas genetic diagrams. The dataset includes >2000 gas samples from the USA, China, Canada, Saudi Arabia, Australia, Sweden, Poland, Argentina, United Kingdom and France. Both free gases collected at wellheads and desorbed gases from cores are included in the dataset. Shale gas samples come from >34 sedimentary basins and >65 different shale formations (plays) ranging in age from Proterozoic (Kyalla and Velkerri Formations, Australia) to Miocene (Monterey Formation, USA). The original data were presented in >80 publications and reports. We plotted molecular and isotopic properties of shale gases on the revised genetic diagrams and determined the origin of shale gases. Based on the distribution of shale gases within the genetic diagram of δ13C of methane (C1) versus C1/(C2+C3), most shale gases appear to have thermogenic origin. The majority of these thermogenic gases are late-mature (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) and mid-mature (associated with oil generation, e.g., Eagle Ford Formation, USA). Importantly, shales may contain early-mature thermogenic gases rarely found in conventional accumulations (e.g., T⊘yen Formation, Sweden and Colorado Formation, Canada). Some shale gases have secondary microbial origin, i.e., they originated from anaerobic biodegradation of oils. For example, gases from New Albany Formation and Antrim Formation (USA) have secondary microbial origin. Relatively few shale gases have primary microbial origin, and they often have some minor admixture of thermogenic gas (e.g., Nicolet Formation, Canada and Alum Formation, Sweden). Two other revised gas genetic plots based on δ2H and δ13C of methane and δ13C of CO2 support and enhance the above interpretation. Although shales that contain secondary microbial gas can be productive (e.g., New Albany Formation, USA), the resource-rich, highly productive and commercially successful shale plays contain thermogenic gas. Plays with late-mature thermogenic gas (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) appear to be most productive.
Na, Li (Faculty of Geographical Science, Beijing Normal University, 100875, Beijing, China) | Jinliang, Zhang (Faculty of Geographical Science, Beijing Normal University, 100875, Beijing, China) | Jinshui, Liu (Shanghai Branch, CNOOC Ltd., 200030, Shanghai, China) | Wenlong, Shen (Shanghai Branch, CNOOC Ltd., 200030, Shanghai, China) | Hao, Chen (Shanghai Branch, CNOOC Ltd., 200030, Shanghai, China) | Guangchen, Xu (Faculty of Geographical Science, Beijing Normal University, 100875, Beijing, China)
Summary The prediction of source rocks is very important to the basin at the initial stage of exploration, among which the description of the source rocks' spatial distribution and the evaluation of the source rocks' thickness are the most significant. For most of the oil and gas fields on the land, the prediction and evaluation of source rocks rely on geochemistry analysis. But well data is inadequate on the offshore exploration area. Therefore, seismic data and geophysical methods can be applied to improve the prediction accuracy of source rocks. Data and Method In this research, the main data relate to core, logging, seismic from Lishui Sag, China (Figure 1).
Simon, Matthieu (Schlumberger) | Tkabladze, Avto (Schlumberger) | Beekman, Sicco (Schlumberger) | Atobatele, Timothy (Schlumberger) | De Looz, Marc-André (Schlumberger) | Grover, Rahul (Schlumberger) | Hamichi, Farid (Schlumberger) | Jundt, Jacques (Schlumberger) | McFarland, Kevin (Schlumberger) | Mlcak, Justin (Schlumberger) | Reijonen, Jani (Schlumberger) | Revol, Arnaud (Schlumberger) | Stewart, Ryan (Schlumberger) | Yeboah, Jonathan (Schlumberger) | Zhang, Yi (Schlumberger)
Formation bulk density is classically measured by irradiating the formation with gamma rays emitted by a 137Cs source, and counting the Compton scattered photons returning to the gamma-ray detectors in the well-logging instrument. Finding a suitable replacement for the 137Cs source has been difficult. The X-ray source described in this paper appears to be a robust replacement for this type of source.
The continued success of 137Cs sources in density logging shows that attempts at their replacement have been unsuccessful due to the insufficient measurement quality or lack of practicality of alternative logging instruments.
An X-ray density-pad sonde was engineered to measure bulk density without a radioisotopic source. The pad contains a rugged, compact X-ray generator with an endpoint energy larger than 300 keV. The core of the tool is the generator, which emits a controlled, focused, stable X-ray flux into the formation. The scattered X-rays are detected by strategically placed scintillation detectors. The pad-tool architecture significantly reduces the effects of standoff and borehole rugosity compared to a mandrel design.
Modeling and experimental data show that the physics of the formation density measurement using a sonde with an X-ray generator and scintillation detectors can be described in the same way as the traditional density measurement, which is based on a monoenergetic gammaray source. Although the 137Cs gamma-ray source density measurement and the X-ray density measurement differ in the relative magnitude of the responses to formation density and lithology (photoelectric factor, PEF), the fundamental physics is the same. An endpoint energy above 300 keV ensures that the transport and attenuation of X-rays in the formation are dominated by Compton scattering, like the attenuation of gamma rays from a 137Cs source. The contribution of the photoelectric absorption to the attenuation of the X-rays is increased, but remains much smaller than the effect of Compton scattering, making the corrections for lithology and borehole fluid straightforward.
A characterization database was acquired to probe the physics of the measurement and to derive robust density and PEF algorithms. Plots of near- and far-detector count rates for different mudcake thicknesses and mud types show spine-and-ribs behavior like 137Cs-based density tools. Field logs acquired with the new tool show improved precision and vertical resolution compared to the 137Cs source tools suggesting that this new tool may be a viable replacement for the older tools.
Yang, Zhao (PetroChina) | Fenjin, Sun (PetroChina) | Bo, Wang (PetroChina) | Xianyue, Xiong (PetroChina) | Wuzhong, Li (PetroChina) | Lianzhu, Cong (PetroChina) | Jiaosheng, Yang (PetroChina) | Meizhu, Wang (PetroChina)
Compared with the conventional oil and gas reservoirs, hydrogeological gas controlling process linking CBM accumulation, enrichment and high yield is one of the important scientific problems for the development of a CBM field. Previous research results are mainly focused on the impact of hydrodynamics on CBM dissipation, preservation and enrichment, whereas relatively less work has been done on the quantitative evaluation of the hydrochemical field of CBM and establishing evaluation indicators of CBM enrichment. Therefore, taking BQ Well area of Hancheng block in east Ordos Basin as an example, this paper tried to initiate a systematic analysis of the controlling function of hydrogeological conditions on the enrichment and high yield of CBM in the study area. Hydrological evaluation indicators for hydrocarbon enrichment zones are established and two favorable hydrocarbon enrichment zones are optimized. It is of great significance for the established analytical method of hydrogeological rule on the studies of CBM enrichment characteristics and development in Hancheng CBM block, and subsequent exploration & development in the neighboring blocks.
Firstly, the relevant principle of hydrodynamics is applied to identify substantive parameters, such as measured in-situ reservoir pressure and CBM reservoir water level in the production wells to calculate the reduced water level and analyze groundwater level distribution characteristics; secondly, combined with the analysis of groundwater water types, the sources of the produced water from coal beds are identified, and the sealing property of the reservoir is demonstrated; on this basis, the study area is divided into the weak runoff zone and the stagnation zone. It is considered that the runoff intensity is relatively weak and the sealing capability is good in the study area, with no external water intrusion; finally, it is considered that, through integrated studies on the hydrochemical field, the desulfuration coefficient and sodium chloride coefficient can reflect the diversity of CBM reservoir conditions in a more elaborated way. Hydrological indicators based on hydrochemical characteristics are established, and two favorable enrichment zones are predicted.
This work proved that hydrogeological features of CBM reservoirs are able to characterize their accumulation conditions elaborately. In particular, the establishment of hydrological indicators can classify favorable enrichment zones and hereafter guide following CBM exploration & development. This methodology has been satisfactorily applied in BQ well area of Hancheng block where the data of gas bearing capacity is limited. High single well production rates have been obtained in the two predicted favorable enrichment zones. The hydrological indicators established in this paper are expected to be popularized and applied in other well areas of Hancheng block, which may accelerate the overall exploration & development progress in this block.
Hydrocarbon-bearing ultra-tight formations generally exhibit heterogeneous, anisotropic, and pressure-dependent petrophysical properties. Consequently, various laboratory measurements on separate core plugs and crushed rock samples from tight formations tend to generate inconsistent petrophysical estimates. These inconsistencies are further escalated by the existence of varied pressure- and pore-size-dependent fluid flow mechanisms in the nanopores of ultra-tight formations. We circumvent such discrepancies in petrophysical estimates by simultaneously estimating six petrophysical parameters from laboratory-based pressure-step-decay measurement on a single ultra-tight rock sample. The proposed method involves nitrogen gas injection into an ultra-tight rock sample at multiple stepwise pressure increments, high-resolution pressure-decay measurement at the outlet, followed by a deterministic inversion of the measured downstream pressure data based on numerical finite-difference modeling of nitrogen gas flow in the ultra-tight rock sample.
This work is performed with an aim to improve the petrophysical estimates previously obtained from pressure-step-decay measurements using only a Klinkenberg-type gas slippage model. We implement a transitional transport model that can handle both slip and diffusion. The proposed method was applied to nine 2-cm-long, 2.5-cm-diameter core plugs extracted from a 1-ft3 ultra-tight pyrophyllite block. We estimated the intrinsic permeability, effective porosity, pore-volume compressibility, pore throat diameter, and two slippage-Knudsen diffusion weight factors parameters. Accuracy of the estimates depends on the physical models incorporated in the forward model and on the error minimization algorithm implemented in the inversion scheme. The estimation results are independent of initial guess of intrinsic permeability, effective porosity pore-volume compressibility, and pore throat diameter in the range of 3 nd to 300 nd, 0.01 to 0.15, 10-2 to 10-6 psi-1, and 60 nm to 500 nm, respectively. The average estimated values of intrinsic permeability, effective porosity, pore-volume compressibility, and pore throat diameter of the nine ultra-tight samples are 86 nd, 0.036, 2.6E-03 psi-1, and 195 nm, respectively. Notably, the two inverted slippage-Knudsen diffusion weight factors indicate that the gas transport mechanism in the nine ultra-tight pyrophyllite samples is completely dominated by slip flow without any Knudsen diffusion or transitional flow even though the Knudsen numbers across the samples during the entire duration of the pressure-step-decay measurements are in the range of 0.01 to 1.
Reservoir depletion results in changes in effective stresses, which may lead to significant changes in reservoir permeability. These changes are associated with matrix compaction, fracture closure and potential slip. A depletion-induced increase in effective stresses often leads to a decrease in permeability. However, the opposite is observed to happen in some fractured gas reservoirs with an organic rock matrix that exhibits strong sorption-mechanical coupling. During depletion, an adsorbed portion of the gas desorbs from micropores resulting in shrinkage of the organic components in the rock matrix, effective stress relaxation and a potential increase in fracture permeability. The objective of this study is to develop a reservoir simulator with a full mechanical coupling accounting for sorption-induced change of stresses. This paper aims to estimate the influence of the parameters affecting reservoir permeability and to predict its evolution during reservoir depletion. We compare two natural gas fields with strong (San Juan coal basin) and weak (Barnett shale formation) sorption-mechanical coupling. The results of the study highlight the interplay between mechanical moduli, swelling isotherm parameters, and fracture compressibility in determining the impact of desorption on fracture permeability evolution during depletion.
Natural gas consumption currently constitutes a fifth of the total energy sources . About a half of nonassociated gas accrues to non-conventional gas reservoirs, mainly organic shales and coal seams . Non-conventional tight reservoirs have an extremely low permeability, a fair portion of which pertains to fractures as main fluid conduits. The openings of these fractures are dictated by lithology and the reservoir stresses, which may alter during reservoir development [2-5]. Two competitive geomechanical processes are known to affect stresses during depletion in organic-rich rocks: pressure drawdown and desorption-induced shrinkage. The latter is of significant importance in coals because sorbed gas constitutes more than 50% of total gas in place and desorption induces a substantial amount of rock shrinkage [6-8]. Sorbed gas in hydrocarbon-bearing shales constitutes 5-15% of the total gas in place. Sorption capacity is usually proportional to total organic carbon (TOC) in shales . Decreases in pore pressure associated with reservoir depletion cause increases in effective stresses, which often leads to fracture closure and a decrease in permeability. In contrast, desorption and matrix shrinkage result in a drop in effective stresses and an increase in permeability [8, 10, 11].
The Niagara Tunnel Project (NTP) is a 10.1 km long water-diversion tunnel in Niagara Falls, Ontario, which was excavated by a 14.4 m diameter tunnel boring machine. The excavated rock types included limestone, sandstone, siltstone, shale and mudstone. Based on observations and measurements the overbreak was divided into four zones. Approximately half the tunnel length was excavated through the Queenston Formation, which locally is a shale to mudstone. Three of the four overbreak zones were within the Queenston. Zone 1 includes the formations above the Queenston Formation, Zones 2 and 4 are border regimes with little or no influence from St. Davids Buried Gorge and Zone 3 is the area influenced by the gorge. Zones 2 through 4 can be generally summarized as having overbreak as the result of stress induced spalling. Zone 2 marks the transition from slabbing at the Whirlpool contact in the stress shadow to spalling towards Zone 3. The behaviour of Zone 3 is interrupted from the typical high stress behaviour due to the presence of St. Davids Buried Gorge. As the tunnel passed from the gorge the high regional stresses induce spalling, which creates the typical notch shaped overbreak geometry of Zone 4.
Three modelling approaches were used to back analyze the brittle failure process at the NTP: damage initiation and spalling limit, laminated anisotropy modelling, and ubiquitous joint approaches. Analyses were conducted for three tunnel chainages: 3+000, 3+250, and 3+500 m because the overbreak depth increased from 2 to 4 m. All approaches produced similar overbreak geometries to those measured. The laminated anisotropy modelling approach was able to produce overbreak depths and chord closures closest to those measured, using a joint normal to shear stiffness ratio between 1 and 2. The back analysis results were able to produce sets of stress and strength inputs for different sections of the tunnel at the transition from overbreak Zone 3 to 4. The back analysis procedure demonstrates the importance of including the anisotropic stiffness in the numerical modelling approach to correctly capture the overbreak geometry and deformations around underground excavations.