Significant research has been conducted on hydrocarbon fluids in the organic materials of source rocks, such as kerogen and bitumen. However, these studies were limited in scope to simple fluids confined in nanopores, while ignoring the multicomponent effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of CO2 injection on the hydrocarbon recovery from organic nanopores. CO2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO2 into the nanopores and the consequential exchange of molecules were the primary drivers that promoted the recovery, whereas pressure depletion was not effective on the recovery. The results for N2 injection were also recorded for comparison.
Reliable estimation of organic matter characteristics is essential in drilling decisions, source rock evaluation, and unconventional reservoir production. Their measurement is based on experiments after core sampling, which is time-consuming and economically challenging. In this study, we present a new approach to evaluate the characteristics of organic matter in source and reservoir rocks by in-situ electrical heating and temperature transient analysis under in-situ conditions.
The new approach is based on inverse modeling, which monitors in-situ heater temperature during electrical heating and machine learning technologies. Thermal method of electrical heating is applied for the in-situ pyrolysis, to figure out the characteristics of organic matter—kerogen volume fraction and activation energy of decomposition reaction. The heater temperature acts as an indicator of type and maturity of kerogen, since it is affected by the bulk thermal conductivity of formation, which is a function of dynamically changing rock-and-pore composition by kerogen decomposition. A full-physics simulation model of in-situ kerogen pyrolysis is used to generate output data of electrical heater temperature, which is the input data of learning-based models. Minimal simplification of physical and chemical phenomena in the full-physics simulation model, which describes the multicomponent-multiphase-nonisothermal systems involving kinetic reactions, gives the confidence of synthetic output data of heater temperature.
Full-physics simulation model computes system responses under unknown and uncertain input parameters, which determine the reactivity of kerogen pyrolysis. The full-physics simulation model generates the sets of heater temperature transient data while heating with constant heat flux, in the 300 different simulated source rocks containing Types 1, 2, and 3 kerogens with various organic matter content and activation energies. Based on the set of heater temperature transient data as input parameters, Artificial Neural Network (ANN) is employed to generate a black box model to estimate the unknown organic matter content and activation energy. Developed ANN data-driven model shows better performance in estimating unknown parameters, in Types 2 and 3 kerogens with wide ranges of activation energies than Type 1 kerogen with a narrow range of activation energy. Support Vector Machines (SVM) method, which categorizes data into multiple classes by using hyperplanes, is applied to classify the heater temperature transient data into different types of kerogens and shows good performance in classification.
The new characterization technology of in-situ organic matter in source rocks presented in this study provides reliable information of types and maturity of organic matter, without experiments after core sampling. It is expected to enable the realistic evaluation of source rocks under subsurface conditions, by resolving technical and economic challenges.
Arisandy, Mellinda (PETRONAS Carigali Indonesia Operations) | Mazied, Miftah (PETRONAS Carigali Indonesia Operations) | Putra, Bayu P (PETRONAS Carigali Indonesia Operations) | Yogapurana, Erik (PETRONAS Carigali Indonesia Operations) | B Mohd Idris, Jamin Jamil (PETRONAS Carigali Indonesia Operations) | Darmawan, Hendra I. (PETRONAS Carigali Kuala Lumpur)
This paper describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.
Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.
This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.
In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.
Cao, Jinrong (The University of Tokyo) | Liang, Yunfeng (The University of Tokyo) | Masuda, Yoshihiro (The University of Tokyo) | Koga, Hiroaki (Japan Oil, Gas and Metals National Corporation) | Tanaka, Hiroyuki (Japan Oil, Gas and Metals National Corporation) | Tamura, Kohei (Japan Oil, Gas and Metals National Corporation) | Takagi, Sunao (Japan Oil, Gas and Metals National Corporation) | Matsuoka, Toshifumi (Fukada Geological Institute)
In this paper, we present an improved method to predict the methane adsorption isotherm for a real shale sample using molecular dynamics (MD) simulation with a realistic kerogen model. We compare our simulation results both to the experiment and to the simulation results on the basis of a simple graphite model, and show how our procedure leads to the creation of more accurate adsorption isotherms of a shale sample at a wide range of pressure. A Marcellus shale sample was chosen as an example to demonstrate how to calculate the adsorption isotherms using MD simulations. Type II kerogen molecular model was selected for the dry gas window. The constructed bulk kerogen model contains mesopores (> 2 nm) and micropores (≤ 2 nm) inside. Ten different mesopore sizes of kerogen nanopore systems were constructed. According to the characteristics of methane density distribution in the simulation system, three regions can be clearly distinguished, free gas, adsorbed gas, and absorbed gas. We show that the adsorbed gas per unit pore volume increases with the pore size decreased. This is similar to previous molecular simulations with graphite model. For predicting the total adsorption isotherm of a real shale sample, both adsorbed and absorbed gas were considered. For the adsorption amount, the calculated adsorption isotherms were averaged based on pore size distribution of that Marcellus Shale sample. For nanopores smaller than 5 nm, we used total organic carbon (TOC) data to weight the absorption contribution in the kerogen bulk (i.e. inside the micropores). The total adsorption isotherm thus obtained from our simulations reproduced experiments very well. Importantly, kerogen model has overcome the difficulties of prediction using graphite models (i.e. an underestimation of adsorption under high pressure conditions) as documented in previous studies. Furthermore, we predicted the adsorption isotherms for higher temperatures. With the temperature increased, lower adsorption amount is predicted. The novelty of our improved method is that it is able to predict methane adsorption isotherm at a wide range of pressure for a shale sample by considering both adsorption in kerogen mesopores and absorption in kerogen bulk. It can be readily used for any shale sample, where the pore size distribution, porosity, and TOC are known. We remark that the above results and conclusion resulted from our simple assumption. Further discussion might be necessary.
Reservoir evaluation of source rock is still a challenge because the geochemical assessment of the kerogen content is complicated and time consuming. Existing traditional methods to characterize kerogen involves the removal of inorganic minerals which is a critical preliminary step. The incomplete isolation of kerogen may introduce some errors and uncertainties in kerogen content estimation. The alteration of kerogen microstructure during this process has also been documented. The current approach still requires input from geochemical measurement of total organic carbon (TOC) while the conversion of TOC to kerogen volume requires the precise value of a conversion factor and kerogen density. Overall, there is yet a standard lab or field scale approach to characterize kerogen content. These difficulties and uncertainties prompt the motivation to attempt a new methodology to quantify the kerogen content of unconventional shale from porosity measurements.
Porosity is the basic rock property that is related to the volumetric average of pore space. The distinction between the total and effective porosity is meaningless for shale and this characteristic property has enabled the preservation of its organic content. The recent popularity and growth of different measurement techniques is in part closely tied to the near zero porosity of shale. Two special cases of practical interest are NMR and density porosity measurements which can both be measured in the rock physics lab and well logs. NMR porosity is sensitive to 1H which is naturally enriched in kerogen whereas density porosity must be calibrated to the mineral matrix.
Based on porosity measurements, the emerging aproach is that the kerogen volume fraction is the contrast between NMR and density porosity. Although, the theoretical basis of this approach is not satisfactory, it is straightforward and far less complicated than the existing approaches to quantify kerogen content. We investigate this concept further based on laboratory measurement. We conducted laboratory measurements of NMR porosity, bulk density, grain density and TOC on Qusaiba shale to characterize its kerogen content. In our approach, we conducted the NMR experiment on the shale samples in the dry state without fluid saturation.
Al-Ibrahim, Abdullah (Kuwait oil Company) | Al-Bader, Haifa (Kuwait oil Company) | Duggirala, Vidya Sagar (Kuwait oil Company) | Ayyavoo, Mani Maran (Kuwait oil Company) | Subban, Packirisamy (Kuwait oil Company) | Almulla, Sulaiman (Kuwait oil Company)
The objective is to achieve improved productivity from an unconventional fractured reservoir using uncemented liner completion over the standard cemented liner completion.
Exploration and production of an unconventional fractured Najmah & Sargelu (NJSR) reservoir in Jurassic section has been a challenging task due to the presence of challenging reservoir quality like tight fractured limestone, very low matrix porosity, uncertainty on natural fractures, high stress, etc. NJSR reservoirs are considered as a secondary target. As the deeper primary reservoir needs to be evaluated, testing of NJSR reservoir takes considerable time after drilling which lead to permanent plugging of NJSR fracture network by invaded oil based mud (OBM). Mixed success has been observed on sustainable production from NJSR exploration wells. Production from fractured reservoir relies primarily on intersecting interconnected natural fractures, optimal drilling and special completion technique. Protecting the natural fractures present in NJSR reservoir can increase the reservoir contact and production.
A study conducted on this reservoir suggested to target only NJSR formation and install uncemented liner to eliminate the damage caused by cement invasion and achieve sustainable production. The study also emphasized to activate the well as soon as possible after completion to revive fracture conductivity. Uncemented perforated liner completion method has been selected for field trail in an exploratory well to maintain borehole integrity and control production of solids, connecting open fractures, increase inflow area and enhance production.
The case study well targeting NJSR reservoir was drilled upto 14,925ft and 5" uncemented CRA liner was installed against reservoir section. The well was completed with permanent packer using 3-1/2" production tubing. Well fluid was displaced with diesel, mud clean solvent was spotted inside 5" production liner and the uncemented liner section was perforated using wire line guns in underbalanced condition. The well became active after perforation and flowed naturally oil and gas with 1.8% H2S.
A successful implementation of uncemented liner completion technique in an exploratory well for the first time proved to be effective in fractured reservoir compared to the conventional cemented liner completion. Application of uncemented liner completion technique has preserved fracture connectivity, eliminated formation damage due to cement invasion and reduced time and cost of cementing and stimulation. During initial testing the first field trial well has produced oil and gas without stimulation, which is a success compared to conventional method.
As a final recommendation from the study, future exploratory wells targeting NJSR reservoir will be drilled in high angle trajectory and completed using uncemented slotted liner with swell packers to improve the productivity.
This paper will discuss in details on new completion strategy, testing of deep HPHT well and performance of first exploratory well completed with uncemented liner.
Crushed shale is commonly used to characterize rock and fluid properties. However, in kerogen-rich rocks, this form of core analysis may not fully account for the effects of nanoporosity and flexibility of the kerogen. To explore the effects of both, we studied capillary condensation and evaporation in crushed, kerogen-rich samples from a shale gas reservoir in the Middle East using repeated injections of n-butane and n-pentane.
A novel, gravimetric capillary condensation apparatus was used to measure isotherms for both n-butane and n-pentane in the crushed samples at temperatures from 4.9 to 65.6°C. The wide temperature range employed allowed us to compare the properties determined at the lower and higher temperatures. Repeated measurements were then used to characterize the consistency of the rock and fluid properties.
Adsorption-and-desorption hysteresis was observed at all temperatures for both fluids. Therefore, routine and special core analysis measurements made during pressure increase may not accurately approximate the pore-fluid occupancy of the reservoir during pressure decrease (i.e., production). Furthermore, it was found that the measured properties were repeatable throughout the n-butane isotherms, while the pore size and fluid density fluctuated during the n-pentane measurements due to irreversible swelling of the kerogen. Thus, core analysis procedures carried out at temperatures different from the reservoir temperature using fluids with compositions dissimilar to that of the reservoir fluid may also result in inaccurate determinations of the rock and fluid properties further introducing significant uncertainties into reservoir performance evaluations.
Although nanopores are known to depress the phase changes of fluids in synthetic media, little is known about their effects on rock and fluid properties at reservoir conditions. This study presents evidence that the phase boundaries of fluids in kerogen-rich shale may significantly differ from those of unconfined fluids in the bulk. We use those measurements to demonstrate the complexities associated with employing the Barrett-Joyner-Halenda technique, which is commonly used for determining the pore size distribution, in shale rock.
The geomechanical properties of reservoirs, which are important for formation stimulation, are often determined from triaxial tests on large-scale samples such as core plugs or blocks. It is difficult to recover large samples from shale formations because they are mechanically unstable and usually break down into pieces. The present study develops a two-scale model that uses drill cuttings to estimate the static elastic properties of shales at the core scale. We first propose a physically representative element to capture the elastic deformation of a solid grain with a known minerology by accounting for the grain size and its elastic properties using the structural-mechanics approach (a small-scale model). We then develop a core-scale model dependent on the volume fractions of the minerals, which are obtained from X-ray diffraction (XRD), for different realizations of the spatial distribution of the solid grains (large-scale model). The sensitivity of the large-scale model to the number of the elements is tested. The proposed model shows promising results for four shale formations (New Albany, Rocky Mountain Siliceous, Lower Bakken, and Barnett) and has major applications for the geomechanical characterization of a formation from drill cuttings.
We introduce a novel well-logging method for determining more-accurate total porosities, fluid volumes, and kerogen volumes in shale-gas and shale-tight-oil wells. Improved accuracy is achieved by self-consistently accounting for the effects of light hydrocarbons and kerogen on the log responses. The logging measurements needed to practice this method are bulk densities, nuclear-magnetic-resonance (NMR) total porosities, and total-organic-carbon (TOC) weight fractions. The TOC weight fractions and the matrix densities, which are used to interpret the bulk density measurements, are both derived from geochemical-tool measurements.
Most unconventional shale-gas and shale-tight-oil reservoirs contain some nonproducible immobile hydrocarbons. When immobile hydrocarbons are present, our method requires prior knowledge of in-situ total water volumes. The water volumes can be estimated from dielectric-tool measurements. In special cases (e.g., in some mature shale-gas reservoirs) where no immobile hydrocarbons are present, a dielectric tool is not needed. In such cases total water volumes are outputs of the method.
We discuss the response functions in shale reservoirs for measurements of bulk densities, NMR porosities, and TOC weight fractions and derive exact self-consistent solutions to the response equations. The algebraic solutions are used to compute shale total porosities, fluid volumes, and kerogen volumes. The predicted shale total porosities and fluid volumes are corrected for light-hydrocarbon effects on the measured bulk densities and NMR porosities and for kerogen effects on the bulk densities. It is shown that significant errors can be made in log-derived shale total porosities if NMR porosities or density-log porosities are assumed to represent true-shale porosities without applying proper corrections.
We discuss the application of the method to the analysis of logging data acquired in a mature shale-gas well drilled in the Marcellus Shale in the northeastern United States and to data acquired in a shale-tight-oil well drilled in the Permian Basin in west Texas. A multifrequency dielectric tool is used to determine in-situ total water volumes in the tight oil well. The mature shale-gas reservoir does not contain immobile hydrocarbons, and, therefore, dielectric-logging measurements were not needed in this well. The results in both wells are shown to compare favorably with core data.
Unconventional and conventional reservoirs do not have much in common. They exhibit different reservoir characteristics; therefore, using conventional reservoir interpretation techniques and workflows in unconventional reservoirs could lead to incorrect conclusions.
In addition to fundamental challenges in evaluating reservoir properties, such as porosity and permeability, it is extremely important to understand reservoir fluid distribution. Downhole fluid typing and calculated volumes, together with porosity and permeability, provide more insight into reservoir potential and sweet spot zones.
Nuclear magnetic resonance (NMR) technology can be used to provide answers to some of the unknowns mentioned previously. Standard NMR measurements provide the lithology-independent porosity and permeability, and then further processing provides more details about partial porosities, volumes, and fluid types occupying the pores. Using two-dimensional maps (2D NMR) helps differentiate the reservoir fluids, especially when distinguishing hydrocarbons (HC) from water. In conventional reservoirs, it is expected to observe faster relaxation for fluid trapped in the smaller pores and longer relaxation for free fluids in the bigger pores. Industry-accepted cutoffs for T1 and T2 measurements help estimate micro, meso, and macro pores. However, for unconventional reservoirs, fluid identification using 2D maps would be different. Fluids in the small pores, such as bitumen, heavy oils, or HCs in source rock reservoir, would have a similar signature on 2D maps.
This paper presents two case studies showing how 2D NMR application was used in an unconventional reservoir for fluid typing processes and HC volumes calculation. It also shows the importance of using this method for more precise planning of further downhole activities. Core data analysis and downhole collected fluid laboratory analysis confirmed the high confidence in NMR fluid typing applications for unconventional reservoirs.