This paper presents a multidomain integrated workflow that combines geophysics, borehole geology, fracture modeling, and petroleum systems analysis for characterization and resource assessment of basement plays. A 3D fracture model is developed by integrating image log interpretation and seismic data to assess the reservoir potential of fractured basement. The 3D fracture modeling is done using the discrete fracture network (DFN) approach with image log interpretation and other fracture drivers serving as the main input. The DFN is upscaled to generate fracture porosity and fracture permeability properties in a 3D grid. The upscaled fracture porosity is used to estimate the petroleum initially in place (PIIP) for the prospects. Multiple 2D petroleum system modeling is performed where large fault throws are identified from seismic interpretation. The petroleum system study helps in identification of areas with most prolific hydrocarbon generation and expulsion centers, which, coupled with the cross-fault juxtapositions, are the main locales of charging for basement reservoir. Further analysis of all the elements of basement play (i.e., source, reservoir, seal, trap, and migration) is done, and prospective areas within the basement play are delineated with high geological chance of success.
Identification of a prospect is normally done based on seismic interpretation and geological understanding of the area. However, due to the inherent uncertainties of the data we still observe in many cases that all key petroleum system elements are present, but still the drilled prospect is dry. Such failures are mostly attributed to a lack of understanding of seal capacity, reservoir heterogeneity, source rock presence and maturation, hydrocarbon migration, and relative timing of these processes. The workflow described in this paper aims to improve discovery success rates by deploying a more rigorous and structured approach. It is guided by the play-based exploration risk assessment process. The starting point is always that the process is guided by the the basic understanding of a mature kitchen should always be based on a regional scale petroleum systems model. However, while evaluating prospects, the migration and entrapment component of a prospect should always be investigated by means of a locally refined grid-based petroleum system model. The uniquepart of this approach is the construction of a high-resolution static model covering the prospects, which is built by using available well data, seismo-geological trends and attributes to capture reservoir potential. Additional inputs such as fault seal analysis also helps to understand prospect scale migration and associated geological risks. In the regional play and local prospect-scale petroleum system models, geological and geophysical inputs are utilized to create the uncertainty distribution for each input parameter which is required for assessing the success case volume of identified prospects. The evaluated risk is combined with the volumetric uncertainty in a probabilistic way to derive the risked volumetrics. It is further translated into an economic evaluation of the prospect by integrating inputs like estimated production profiles, appropriate fiscal models, HC price decks, etc. This enables the economic viability of the prospects to be assessed, resulting in a portfolio with proper ranking to build a decision-tree leading to execution and operations in ensuing drilling campaigns.
Seunghwan Baek and I. Yucel Akkutlu, Texas A&M University Summary Source rocks, such as organic-rich shale, consist of a multiscale pore structure that includes pores with sizes down to the nanoscale, contributing to the storage of hydrocarbons. In this study, we observed hydrocarbons in the source rock partition into fluids with significantly varying physical properties across the nanopore-size distribution of the organic matter. This partitioning is a consequence of the multicomponent hydrocarbon mixture stored in the nanopores, exhibiting a significant compositional variation by pore size-- the smaller the pore size, the heavier and more viscous the hydrocarbon mixture becomes. The concept of composition redistribution of the produced fluids uses an equilibrium molecular simulation that considers organic matter to be a graphite membrane in contact with a microcrack that holds bulk-phase produced fluid. A new equation of state (EOS) was proposed to predict the density of the redistributed fluid mixtures in nanopores under the initial reservoir conditions. A new volumetric method was presented to ensure the density variability across the measured pore-size distribution to improve the accuracy of predicting hydrocarbons in place. The approach allowed us to account for the bulk hydrocarbon fluids and the fluids under confinement. Multicomponent fluids with redistributed compositions are capillary condensed in nanopores at the lower end of the pore-size distribution of the matrix ( 10 nm). The nanoconfinement effects are responsible for the condensation. During production and pressure depletion, the remaining hydrocarbons become progressively heavier. Hence, hydrocarbon vaporization and desorption develop at extremely low pressures. Consequently, hydrocarbon recovery from these small pores is characteristically low. Introduction Resource shale and other source-rock formations with significant amounts of organic matter, such as mudstone, siltstone, and carbonate, have a multiscale pore structure that includes fractures, microcracks, and pores down to a few nanometers (Ambrose et al. 2012; Loucks et al. 2012). The total amount of hydrocarbons stored is directly proportional to the amount of organic matter.
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.
A novel formulation for modeling nonlinear reactive-compositional transport comprising of complex phase behaviors with chemical and thermodynamic interactions is presented. The precipitation/dissolution of minerals during reactive flow in subsurface reservoirs is modeled in the newly designed simulation framework. This framework uses molar formulation with a consistent reduction of governing mass balance equations from component to element mole fractions. The thermodynamic phase behaviour is extended by including the chemical equilibrium reactions in the multiphase thermodynamic flash. This allows for a general treatment of chemical and thermodynamic equilibrium in a fully couple and implicit manner. The governing component conservation equations are reduced to element conservation equations using the Equilibrium Rate Annihilation matrix. The element composition of the mixture serves as an input for these computations whereas the output is fractions of components in each phase, including solids. To solve the resulting nonlinear element based governing equations, we use the Adaptive Operator-Based Linearization (OBL) approach where the governing equations are formulated in terms of space and state-dependent parameters. The proposed framework is utilized for modeling of several challenging flow and transport problems with dissolution and precipitation reactions. This is the first time when a multiphase multicomponent flash using element fractions as an input is coupled with an element balance compositional formulation and validated for multidimensional problems of practical interest. In addition, an efficient parametrization using adaptive OBL approach improves both robustness and performance of complex reactive-compositional flow and transport.
Tight oil and shale gas reservoirs have a significant part of their pore volume occupied by micro (below 2nm) and mesopores (between 2 and 50nm). This kind of environment creates strong interactions forces in the confined fluid with pore walls as well as between its own molecules and then changes dramatically the fluid phase behavior and its thermodynamic properties. Pressure-Vapor-Temperature (
We present a new fully-implicit, hybrid-mixed, mimetic finite difference (HMFD) discretization scheme for general-purpose compositional reservoir simulation. The locally conservative scheme solves the coupled momentum and mass balance equations simultaneously, and the fluid system is modeled using a cubic equation-of-state. We compare the method to other discretization schemes for unstructured meshes and tensor permeability. Finally, we illustrate the applicability and robustness of the method for highly heterogeneous reservoirs with unstructured grids.
Li, Nianyin (Southwest Petroleum University) | Kang, Jia (Southwest Petroleum University) | Zhang, Qian (Southwest Petroleum University, Research Institute of Natural Gas Technology, PetroChina Southwest Oil & Gas field Company) | Wu, Yu (Southwest Petroleum University) | Zhang, Haotian (Southwest Petroleum University)
Considering characteristics of complex carbonate reservoirs (e.g., high depth, high temperature, and fracture cave development), this paper simulates expansion of the acid wormhole when combining diverting acid and a solid diverting agent for acid fracturing. Using the theory of reaction kinetics, tests of diverting acid reaction kinetics, and flow reaction experiments on the long core and parallel core, this paper presents tests of the acid–rock reaction for a mathematical model of acid diversion. On the basis of a rheological behavior test of diverting acid, we studied the influences of Ca2+ concentration, pH, fiber concentration, and temperature on acid system viscosity. Then, we established a mathematical model of changes in diverting acid viscosity under a multi-factor cooperative control mechanism. On the basis of the kriging method, we established a three-dimensional (3D) geological model involving a random normal distribution and spatial correlation of multi-fracture and pore-permeability properties. We used four models (acid rock reaction rate, viscosity change, 3D acid wormhole expansion, and fluid–solid coupling) of a complex system to study dynamic cooperation characterization of diverting acid and a solid diverting agent under multiple factors. Simulation results show that the temporary plugging of acid and expansion of acid wormholes are mutually restricted. The solid diverting agent blocked the fracture, and a dense filter cake formed at the start of the fracture; thus, the physical flow direction of diverting acid changed, the acid wormhole length increased, and filtration of diverting acid declined to improve the acid's effect. Diverting acid and solid diverting agent work more effectively together. This paper is novel because we consider the respective influences of Ca2+ concentration, pH, flow rate, diverting acid rheological properties, injection parameters, and solid diverting agent concentration on the synergistic steering of steering acid and a solid diverting agent. We then establish a mathematical model to reflect complex stratigraphic conditions and objectively describe the acid flow reaction. We also innovatively solve the problem of predicting acid wormhole expansion given complex fractures and uneven pore distribution. Findings provide a theoretical basis and technical support for the application of acid fracturing in complex carbonate reservoirs.
Jia, Wenlong (Southwest Petroleum University) | Yang, Fan (Southwest Petroleum University) | Mu, JunCheng (Kongsberg Gigital AS) | Cheng, Tingting (Southwest Petroleum University) | Li, Changjun (Southwest Petroleum University) | Zhang, Qi (Deepwater Engineering & Construction Center CNOOC China Ltd.-Shenzhen Branch)
Co-existence of gas, water and glycol is commonly in produced fluids of high-pressure gas wells due to formation water production and hydrate inhibitor injection. The interaction between the polar water and glycol molecules can affect the phase behavior and subsequent temperature change during gas flowing through chokes at wellheads. This paper presents an isenthalpic flash method based on the cubic-plus-association equation of state (CPA EOS) to calculate the temperature at the downstream of the choke. In comparison with the traditional isenthalpic flash algorithm, this new method accounts for the self- and cross-association between polar water and glycol molecules, yielding more accurate enthalpy calculation results for fluid containing water and glycol as well as choke temperatures. The proposed model is validated with field test data. Results demonstrate that the average absolute deviations between the measured and calculated temperatures at downstream of chokes based on the proposed method are less than 1.6°C even for vapor-liquid-aqueous three-phase mixtures at pressures up to 100 MPa. Results yield from the proposed method are more accurate than those calculated from the SRK EOS combining with the Peneloux volume shift method and the Huron-Vidal mixing rule.
Chen, Li (Schlumberger) | Gan, Yunyan (CNOOC) | Gao, Bei (Schlumberger) | Chen, Jichao (Schlumberger) | Canas, Jesus A. (Schlumberger) | Jackson, Richard (Schlumberger) | EI-Khoury, Jules (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Reservoir connectivity is always the major concern for reservoir evaluation. In addition, reservoirs exhibit all manners of complexities that introduce many other production concerns such as aquifer support, viscous oil, low productivity index, and high AOP. Improved methods of reservoir evaluation are needed. A new discipline Reservoir Fluid Geodynamics (RFG) provides a powerful framework to significantly improve reservoir understanding and naturally allows substantial data integration across many discipline. Many reservoir fluids have been altered by reservoir fluid geodynamic (RFG) processes such as a late gas charge, asphaltene migration, biodegradation, water washing, which complicate fluid distributions and produces extra challenges to understand connectivity and other reservoir concerns. Identifying and quantifying the alteration processes will be key issues addressed herein. This RFG approach also helps to clarify complexities associated with reservoir concerns such as asphaltene stability, composition gradients, viscosity variations, tar mat formation, and fault block migration.
This paper describes an integrated approach within an RFG framework to understand reservoir connectivity and fluid alteration processes. This approach is founded on simple asphaltene thermodynamics and the ability to identify fluid equilibration utilizing the Flory-Huggins-Zuo Equation of State (FHZ EoS) with its reliance on the Yen-Mullins model. This model classifies the asphaltene species dispersed in crude oil in 3 different forms: molecules, nanoaggregates (of molecules) and clusters (of nanoaggregates). For low concentrations of asphaltenes, they are present in crude oils as a true molecular solution and corresponds to the Light Oil Model. At higher asphaltene concentrations, they are present as nanoaggregates giving the Black Oil Model and at even higher concentrations, they are present as clusters giving the Heavy Oil Model. Gas charge into reservoirs can destabilized asphaltenes and can change their colloidal description causing a transition in the appropriate model for describing asphaltene (and viscosity) gradients. Continued asphaltene instability can yield tar mat or local asphaltene deposition. The Flory-Huggins-Zuo Equation of State (FHZ EoS) is best used in conjunction with Downhole Fluid Analysis (DFA) to delineate these asphaltene gradients. This thermodynamic analysis of asphaltene gradient and GOR gradient using the Cubic EoS is best linked with high resolution analytical chemistry such as two-dimensional gas chromatography (GCxGC) and GC compositional analysis with geochemical interpretation. Fluid inclusion analysis is particularly useful to identify fluid type that occupied the reservoir in the geologic past. The stable isotope analysis of methane and other gases helps identify specific fluids that entered the reservoir.
The paper presents a case study from Gulf of Mexico and include data from three stacked reservoirs in a single reservoir. Each sand received two charges, an initial (light) black oil charge and a subsequent primary biogenic charge. Even with this simple scenario, three totally different fluids are found at the well location in each of the three sands. One sand currently contains a black oil with moderate GOR having received limited biogenic gas, a second sand contains a near critical fluid with both gas and oil phases, and the third sand contains a dry gas, the gas having blown out all the oil. The FHZ EoS is shown to apply for connectivity analysis as validated by many other methods. In the black oil column, some asphaltene instability caused by the late gas charge created a heavy oil at the oil-water contact. Lab measurements of Asphaltene Onset Pressure (AOP) confirmed this evaluation. The integration of asphaltene gradient modeling, DFA, gas isotopes, fluid inclusions, Cubic EoS, GCxGC with geochemical analysis provides a novel and systematic approach and should be considered for most conventional reservoirs.