2017 Vol. 28, No. 5
As shale exploitation is still in its infancy outside North America much research effort is being channelled into various aspects of geochemical characterization of shales to identify the most prospective basins, formations and map their petroleum generation capabilities across local, regional and basin-wide scales. The measurement of total organic carbon, distinguishing and categorizing the kerogen types in terms oil-prone versus gas-prone, and using vitrinite reflectance and Rock-Eval data to estimate thermal maturity are standard practice in the industry and applied to samples from most wellbores drilled. It is the trends of stable isotopes ratios, particularly those of carbon, the wetness ratio (C1/∑(C2+C3)), and certain chemical biomarkers that have proved to be most informative about the status of shales as a petroleum system. These data make it possible to identify production "sweet-spots", discriminate oil-, gas-liquid-and gas-prone shales from kerogen compositions and thermal maturities. Rollovers and reversals of ethane and propane carbon isotope ratios are particularly indicative of high thermal maturity exposure of an organic-rich shale. Comparisons of hopane, strerane and terpane biomarkers with vitrinite reflectance (Ro) measurements of thermal maturity highlight discrepancies suggesting that Ro is not always a reliable indicator of thermal maturity. Major and trace element inorganic geochemistry data and ratios provides useful information regarding provenance, paleoenvironments, and stratigraphic-layer discrimination. This review considers the data measurement, analysis and interpretation of techniques associated with kerogen typing, thermal maturity, stable and non-stable isotopic ratios for rocks and gases derived from them, production sweet-spot identification, geochemical biomarkers and inorganic chemical indicators. It also highlights uncertainties and discrepancies observed in their practical application, and the numerous outstanding questions associated with them.
Modeling geomechanical properties of shales to make sense of their complex properties is at the forefront of petroleum exploration and exploitation application and has received much research attention in recent years. A shale's key geomechanical properties help to identify its "fracibility" its fluid flow patterns and rates, and its in-place petroleum resources and potential commercial reserves. The models and the information they provide, in turn, enable engineers to design drilling patterns, fracture-stimulation programs and materials selection that will avoid formation damage and optimize recovery of petroleum. A wide-range of tools, technologies, experiments and mathematical techniques are deployed to achieve this. Characterizing the interconnected fracture, permeability and porosity network is an essential step in understanding a shales highly-anisotropic features on multiple scales (nano to macro). Well-log data, and its petrophysical interpretation to calibrate many geomechanical metrics to those measured in rock samples by laboratory techniques plays a key role in providing affordable tools that can be deployed cost-effectively in multiple well bores. Likewise, microseismic data helps to match fracture density and propagation observed on a reservoir scale with predictions from simulations and laboratory tests conducted on idealised/simplified discrete fracture network models. Shales complex wettability, adsorption and water imbibition characteristics have a significant influence on potential formation damage during stimulation and the short-term and long-term flow of petroleum achievable. Many gas flow mechanisms and models are proposed taking into account the multiple flow mechanisms involved (e.g., desorption, diffusion, slippage and viscous flow operating at multiple porosity levels from nano-to macro-scales). Fitting historical production data and well decline curves to model predictions helps to verify whether model's geomechanical assumptions are realistic or not. This review discusses the techniques applied and the models developed that are relevant to applied geomechanics, highlighting examples of their application and the numerous outstanding questions associated with them.
Thermal maturation and petroleum generation modeling of shales is essential for successful exploration and exploitation of conventional and unconventional oil and gas plays. For basin-wide unconventional resource plays such modeling, when well calibrated with direct maturity measurements from wells, can characterize and locate production sweet spots for oil, wet gas and dry gas. The transformation of kerogen to petroleum is associated with many chemical reactions, but models typically focus on first-order reactions with rates determined by the Arrhenius Equation. A misconception has been perpetuated for many years that accurate thermal maturity modeling of vitrinite reflectance using the Arrhenius Equation and a single activation energy, to derive a time-temperature index (∑TTIARR), as proposed by
This paper presents the rheological behaviour of supercritical CO2 (sCO2) foam at reservoir conditions of 1 500 psi and 80 ℃. Different commercial surfactants were screened and utilized in order to generate a fairly stable CO2 foam. Mixed surfactant system was also introduced to generate strong foam. Foam rheology was studied for some specific foam qualities using a high pressure high temperature (HPHT) foam loop rheometer. A typical shear thinning behaviour of the foam was observed and a significant increase in the foam viscosity was noticed with the increase of foam quality until 85%. A desired high apparent viscosity with coarse texture was found at 85% foam quality. Foam visualization above 85% showed an unstable foam due to extremely thin lamella which collapsed and totally disappeared in the loop rheometer. Below 52%, a non-homogenous and unstable foam was found having low viscosity with some liquid accumulation at the bottom of the circulation loop. This research has demonstrated rheology of sCO2 foams at different qualities at HPHT to obtain optimal foam quality region for immiscible CO2 foam co-injection process.
Offshore drilling and production operations can result in spills or leaks of hydrocarbons into seabed sediments, which can potentially contaminate these sediments with oil. If this oil later migrates to the water surface it has the potential for negative environmental impacts. For proper contingency planning and to avoid larger consequences in the environment, it is essential to understand mechanisms and rates for hydrocarbon migration from oil containing sediments to the water surface as well as how much will remain trapped in the sediments. It is believed that the amount of oil transported out of the sediment can be affected by tidal pumping, a common form of subterranean groundwater discharge (SGD). However, we could find no study experimentally investigating the phenomenon of fluid flow in subsea sediments containing oil and the effects of tidal pumping. This study presents an experimental investigation of tidal pumping to determine if it is a possible mechanism that may contribute to the appearance of an oil sheen on the ocean surface above a sediment bed containing oil. An experimental apparatus was constructed of clear PVC pipe allowing for oil migration to be monitored as it flowed out of a sand pack containing oil, while tidal pressure oscillations were applied in three different manners. The effect of tidal pumping was simulated via compression of air above the water (which simulated the increasing static head from tidal exchange). Experimental results show that sustained oil release occurred from all tests, and tests with oscillating pressure produced for longer periods of time. Furthermore, the experimental results showed that the oil migration rate was affected by grain size, oil saturation, and oscillation wave type. In all oscillating experiments the rate and ultimate recovery was less than the comparable static experiments. For the conditions studied, the experimental results indicate that with an oscillating pressure on top of a sand pack, movement of a non-replenishing source of oil is suppressed by pressure oscillation.
Transient rate decline curve analysis for constant pressure production is presented in this paper for a naturally fractured reservoir. This approach is based on exponential and constant bottom-hole pressure solution. Based on this method, when ln (flow rate) is plotted versus time, two straight lines are obtained which can be used for estimating different parameters of a naturally fractured reservoir. Parameters such as storage capacity ratio (ω), reservoir drainage area (A), reservoir shape factor (CA), fracture permeability (kf), interporosity flow parameter (λ) and the other parameters can be determined by this approach. The equations are based on a model originally presented by Warren and Root and extended by Da Prat et al. and Mavor and Cinco-Ley. The proposed method has been developed to be used for naturally fractured reservoirs with different geometries. This method does not involve the use of any chart and by using the pseudo steady state flow regime, the influence of wellbore storage on the value of the parameters obtained from this technique is negligible. In this technique, all the parameters can be obtained directly while in conventional approaches like type curve matching method, parameters such as ω and λ should be obtained by other methods like build-up test analysis and this is one of the most important advantages of this method that could save time during reservoir analyses. Different simulated and field examples were used for testing the proposed technique. Comparison between the obtained results by this approach and the results of type curve matching method shows a high performance of decline curves in well testing.
Tight zones of the gas bearing Kangan and Dalan formations of the South Pars gas field contain a considerable amount of unswept gas due to their low porosity, low permeability and isolated pore types. The current study, integrates core data, rock elastic properties and 3D seismic attributes to delineate tight and low-reservoir-quality zones of the South Pars gas field. In the first step, the dynamic reservoir geomechanical parameters were calculated based on empirical relationships from well log data. The log-derived elastic moduli were validated with the available laboratory measurements of core data. Cross plots between estimated porosity and elastic parameters based on Young's modulus indicate that low porosity zone coincide with high values of Young's module. The results were validated with petrographic studies of the available thin sections. The core samples with low porosity and permeability are correlated with strong rocks with tight matrix frameworks and high elastic values. Subsequently, rock elastic properties including Young's modulus and Poisson's ratio along with porosity were estimated by using neural networks from a collection of 3D post-stack seismic attributes, such as acoustic impedance (AI), instantaneous phase of AI and apparent polarity. Distinguishing low reservoir quality areas in pay zones with unswept gas is then facilitated by locating low porosity and high elastic modulus values. Anhydrite zones are identified and eliminated as non-pay zones due to their characterization of zero porosity and high Young modulus values. The methodology described has applications for unconventional reservoirs more generally, because it is able to distinguish low porosity and permeability zones that are potentially productive from those unprospective zones with negligible reservoir quality.
The Rocky Mountain Foothills lie along the eastern margin of the Rocky Mountain fold-thrust belt. The area has been the focus of extensive research aimed at locating oil and gas fields with the potential to be used as CO2 storage traps. In this study, we use a seismic line from the Canadian Rockies to interpret the geologic structures along a cross-section parallel to the tectonic transport direction. We then compare our results with those of previous studies. The section was restored using the MOVE software (manufactured by Midland Valley Exploration Ltd.). The primary objectives of this work are: (1) to conduct a stratigraphic and structural interpretation of a 2D seismic profile; and (2) to conduct a cross-sectional restoration of the structures in order to validate the seismic interpretation in terms of CO2 storage candidates. Additional data sources include maps of the surface geology, which show that the age of horizons decrease from west to east, and stratigraphic and structural profiles derived from well logs. The results of our structural restoration indicate a detachment fault between the foreland and hinterland. This fault is responsible for the cutting and subsequent upwards and eastwards movement of a stratum located between the basement and the Late Devonian formation. Large thrust faults are responsible for the deformation of strata (through both folding and faulting) in the foreland basin. As a result of continuous eastward tectonic stress, the strata from Jurassic have deformed, forming a duplex system in the middle of the section and resulting in the uplift of the upper part of the section. Following surface erosion, this uplifted area became exposed during the Tertiary Period. The high shortening rate (53%) detected through structural restoration is consistent with the thin-skinned tectonic model.
Understanding of fundamental processes and prediction of optimal parameters during the horizontal drilling and hydraulic fracturing process results in economically effective improvement of oil and natural gas extraction. Although modern analytical and computational models can capture fracture growth, there is a lack of experimental data on spontaneous imbibition and wettability in oil and gas reservoirs for the validation of further model development. In this work, we used neutron imaging to measure the spontaneous imbibition of water into fractures of Eagle Ford shale with known geometries and fracture orientations. An analytical solution for a set of nonlinear second-order differential equations was applied to the measured imbibition data to determine effective contact angles. The analytical solution fit the measured imbibition data reasonably well and determined effective contact angles that were slightly higher than static contact angles due to effects of in-situ changes in velocity, surface roughness, and heterogeneity of mineral surfaces on the fracture surface. Additionally, small fracture widths may have retarded imbibition and affected model fits, which suggests that average fracture widths are not satisfactory for modeling imbibition in natural systems.
A protocol for obtaining digital images from natural porous media with a wide range of pore sizes, intended for fractal studies of the porosity, is proposed. Soil porosity is used as paradigm of complex natural porous media in this study. The use of several imaging devices and fluorescent compounds to enhance the contrast between the solid and the pore phase is tested. Finally a protocol is reached using a photo camera and a confocal microscope. It is the first time that confocal microscopy is used for this purpose. Artificial porous images are created through random Sierpinski carpet fractals and the statistical information of real soil images. These ground truth images are used in an objective comparison of automatic segmentation algorithms for the obtained images. A statistical classification on the performance of several automatic segmentation algorithms for this type of images is reached.
The shale deposits of Damodar Valley have received great attention since preliminary studies indicate their potential for shale gas. However, fundamental information allied to shale gas reservoir characteristics are still rare in India, as exploration is in the primary stage. In this study, Barakar shale beds of eastern part of Jharia Basin are evaluated for gas reservoir characteristics. It is evident that Barakar shales are carbonaceous, silty, contains sub-angular flecks of quartz and mica, irregular hair-line fractures and showing lithological variations along the bedding planes, signifying terrestrial-fluviatile deposits under reducing environment. The values of TOC varies from 1.21 wt.% to 17.32 wt.%, indicating good source rock potentiality. The vitrinite, liptinite, inertinite and mineral matter ranging from 0.28 vol.% to 12.98 vol.%, 0.17 vol.% to 3.23 vol.%, 0.23 vol.% to 9.05 vol.%, and 74.74 vol.% to 99.10 vol.%, respectively. The ternary facies plot of maceral composition substantiated that Barakar shales are vitrinite rich and placed in the thermal-dry gas prone region. The low values of the surface area determined following different methods point towards low methane storage capacity, this is because of diagenesis and alterations of potash feldspar responsible for pore blocking effect. The pore size distribution signifying the micro to mesoporous nature, while Type Ⅱ sorption curve with the H2 type of hysteresis pattern, specifies the heterogeneity in pore structure mainly combined-slit and bottle neck pores.
Carbon dioxide (CO2) enhanced coalbed methane (ECBM) is an effective method to improve methane (CH4) production and this technology has already been used to increase gas production in several field trials worldwide. One major problem is the injection drop in the later period due to permeability decrease caused by coal matrix swelling induced by CO2 injection. In order to quantify the swelling effect, in this work, coal samples were collected from the Bulli coal seam, Sydney Basin and adsorption tests with simultaneous matrix swelling measurement were conducted. The adsorption and swelling characteristics were analyzed by measuring the adsorption mass simultaneously with the strain measurement. Then experiments were conducted to replicate the ECBM process using the indirect gravity method to obtain the swelling strain change with CO2 injection. The results show that the coal adsorption capacity in CO2 is almost two times greater than that in CH4, and nitrogen adsorption is the least among these gases. A Langmuir-like model can be used to describe the strain with the gas pressure and the swelling strain induced by gas adsorption has a linear relationship with gas adsorption quantity. Moreover, swelling strain increase was observed when CO2 was injected into the sample cell and the swelling strain was almost the sum of the strains induced by different gases at corresponding partial gas pressure.
Organic-rich shale resources remain an important source of hydrocarbons considering their substantial contribution to crude oil and natural gas production around the world. Moreover, as part of mitigating the greenhouse gas effects due to the emissions of carbon dioxide (CO2) gas, organic-rich shales are considered a possible alternate geologic storage. This is due to the adsorptive properties of organic kerogen and clay minerals within the shale matrix. Therefore, this research looks at evaluating the sequestration potential of carbon dioxide (CO2) gas in kerogen nanopores with the use of the lattice Boltzmann method under varying experimental pressures and different pore sizes. Gas flow in micro/nano pores differ in hydrodynamics due to the dominant pore wall effects, as the mean free path (λ) of the gas molecules become comparable to the characteristic length (H) of the pores. In so doing, the traditional computational methods break down beyond the continuum region, and the lattice Boltzmann method (LBM) is employed. The lattice Boltzmann method is a mesoscopic numerical method for fluid system, where a unit of gas particles is assigned a discrete distribution function (f). The particles stream along defined lattice links and collide locally at the lattice sites to conserve mass and momentum. The effects of gas-wall collisions (Knudsen layer effects) is incorporated into the LBM through an effective-relaxation-time model, and the discontinuous velocity at the pore walls is resolved with a slip boundary condition. Above all, the time lag (slip effect) created by CO2 gas molecules due to adsorption and desorption over a time period, and the surface diffusion as a result of the adsorption-gradient are captured by an adsorption isotherm and included in our LBM. Implementing the Langmuir adsorption isotherm at the pore walls for both CO2 gas revealed the underlying flow mechanism for CO2 gas in a typical kerogen nano-pore is dominated by the slip flow regime. Increasing the equilibrium pressure, increases the mass flux due to adsorption. On the other hand, an increase in the nano-pore size caused further increase in the mass flux due to free gas and that due to adsorbed gas. Thus, in the kerogen nano-pores, CO2 gas molecules are more adsorptive indicating a possible multi-layer adsorption. Therefore, this study not only provides a clear understanding of the underlying flow mechanism of CO2 in kerogen nano-pores, but also provides a potential alternative means to mitigate the greenhouse gas effect (GHG) by sequestering CO2 in organic-rich shales.
Our database tracking of USA water usage per well indicates that traditionally shale operators have been using, on average 3 to 6 million gallons of water; even up to 8 million for the entire life cycle of the well based on its suitability for re-fracturing to stimulate their long and lateral horizontal wells. According to our data, sourcing, storage, transportation, treatment, and disposal of this large volume of water could account for up to 10% of overall drilling and completion costs. With increasingly stringent regulations governing the use of fresh water and growing challenges associated with storage and use of produced and flowback water in hydraulic fracturing, finding alternative sources of fracturing fluid is already a hot debate among both the scientific community and industry experts. On the other hand, waterless fracturing technology providers claim their technology can solve the concerns of water availability for shale development. This study reviews high-level technical issues and opportunities in this challenging and growing market and evaluates key economic drivers behind water management practices such as waterless fracturing technologies, based on a given shale gas play in the United States and experience gained in Canada. Water costs are analyzed under a variety of scenarios with and without the use of (fresh) water. The results are complemented by surveys from several oil and gas operators. Our economic analysis shows that fresh water usage offers the greatest economic return. In regions where water sourcing is a challenge, however, the short-term economic advantage of using non-fresh water-based fracturing outweighs the capital costs required by waterless fracturing methods. Until waterless methods are cost competitive, recycled water usage with low treatment offers a similar net present value (NPV) to that of sourcing freshwater via truck, for instance.
Most of the onshore and offshore oil and gas reservoirs are facing operational challenges due to high temperature and high salinity, thus requiring advanced techniques for realizing the expected oil recovery with the use of specially designed chemicals. During oil and gas well development, completion fluids, which are solids-free liquids, are used to complete an oil or gas well. Completion fluids consisting of brines are primarily used for oil and gas well stabilization and are corrosive in nature. There is a need to develop additives to be added with completion fluids to address the corrosive nature. The present investigation involved the usage of two imidazolium ionic liquids (ILs) as corrosion inhibitors for mild steel in various completion brine (CaCl2, HCOOCs and ZnBr2) fluids. The study was performed using various techniques, such as, potentiodynamic polarization, weight loss measurements and exposure studies. All the above techniques showed promising results which indicated that the ILs as corrosion inhibitors used were of the mixed-type following both physisorption and chemisorption over the mild steel surface. Among the two inhibitors studied here, 1-octyl-3-methyl imidazolium chloride ([OMIM]+[Cl]-) with longer alkyl chain exhibited better inhibition efficiency and much lesser corrosion rate than 1-butyl-3-methyl imidazolium chloride ([BMIM]+[Cl]-) with a shorter alkyl chain. The results obtained from various methodologies indicate that ionic liquids can be explored to develop anti-corrosive completion fluids suitable for oil and gas reservoirs.