Smith, Robert (Geophysics Technology, EXPEC Advanced Research Center) | Bakulin, Andrey (Geophysics Technology, EXPEC Advanced Research Center) | Jervis, Mike (Geophysics Technology, EXPEC Advanced Research Center) | Hemyari, Emad (Geophysics Technology, EXPEC Advanced Research Center) | Alramadhan, Abdullah (Geophysics Technology, EXPEC Advanced Research Center) | Erickson, Kevin (Geophysics Technology, EXPEC Advanced Research Center)
Saudi Aramco recently started the company's first CO2-EOR demonstration project in an onshore carbonate reservoir. Time-lapse (4D) seismic has proven to be a valuable reservoir management tool for monitoring the areal expansion of CO2 plumes in many similar projects around the world. However, the complex and dynamic nature of the near surface encountered in the desert environments of the Middle East results in high levels of 4D noise. This noise, coupled with the weak 4D signal expected from injection into a stiff carbonate reservoir, makes mapping the time lapse signal very challenging. The objective of this project was to develop a highly repeatable system capable of detecting small reservoir changes related to CO2 injection to enable the plume expansion to be tracked over time.
Achieving highly repeatable seismic data requires specialized seismic acquisition and dedicated processing. A novel acquisition system using buried receivers was adopted to reduce 4D noise resulting from near-surface variations. To minimize the non-repeatability inherent in using surface sources, a differential GPS guidance system was implemented to ensure high positioning accuracy. Even with these acquisition efforts, a fit-for-purpose 4D processing workflow was necessary to further reduce differences between surveys.
Despite the challenges faced, outstanding data repeatability has been achieved, with mean NRMS values of less than 5% for data acquired during the same season. This level of repeatability is comparable to data acquired in marine 4D surveys and has resulted in the detection of the small 4D signal caused by CO2 injection. Frequent monitor surveys, with one full survey acquired every four weeks, shows the CO2 plume growing over time with increasing injection volume. While the observed CO2 plume largely correlates to available engineering data, discrepancies have been identified when compared with the predicted seismic response based on the reservoir simulation model. This indicates that 4D seismic can be used to constrain the reservoir model, yielding a better history match and improved predictions to enable more informed engineering decisions to be made.
This is the first successful application of seismic monitoring of a carbonate reservoir in an area renowned for poor seismic data quality. To overcome the challenges, a novel hybrid acquisition system using buried sensors and surface sources was developed. Advances in the seismic processing workflow were also required to bring the 4D noise down to a level that enabled detection of the CO2 injection.
Mixing of an asphaltenic oil with light gases (e.g., CO2) and/or depressurizing such a crude oil can lead to phase separation in which a second liquid phase L2 -highly concentrated in asphaltene- is formed. Asphaltene may precipitate or deposit out of the second liquid phase. This causes formation damage, wettability alteration, and recovery reduction. While asphaltene phase behavior have been studied under static conditions (where equilibrium is imposed), the behavior of asphaltene under dynamic flow conditions is relatively unexplored. Here, we investigate the coupling of asphaltene phase behavior and flow in porous media. As such, two asphaltenic crudes are characterized using the PC-SAFT equation-of- state. The fluid models were then used to fit the experimental asphaltene deposition data under static conditions. Subsequently, asphaltene flow and deposition was studied during miscible gas flooding where four phases (water, oil L1, gas, and second liquid L2) are present. Our results show that (i) wettability alteration increases the mixing zone and decreases both the displacement and sweep efficiencies; (ii) asphaltene deposition, hence wettability alteration and formation damage are maximal near the producer.
Single-well chemical tracer (SWCT) is the most commonly used field method to determine oil or water saturation in one-well enhanced-oil-recovery (EOR) pilots. Because hydrolysis of an ester, which is the main part of the method, leads to forming acid as well as alcohol, the equilibrium state of the reservoir is disturbed, and thus the pH changes. It is generally accepted that the hydrolysis-reaction rate is mainly dependent on the pH and temperature. Therefore, it is required to know the extent to which this dependency might affect the shape of the product-tracer profiles and the numerical interpretation of the field-test data for computing residual oil saturation (Sor). In this study, this notion has been investigated by coupling a multiphase-flow simulator to the geochemistry package PHREEQC (Parkhust and Appelo 2013).
In this study, the PHREEQC geochemical simulator has been used to illustrate the extent to which different parameters might affect the pH variation during the test. The PHREEQC database has been modified to take the ester-hydrolysis reaction into account by adding the ester, alcohol, and acid-product species. The hydrolysis-reaction mechanisms of ester have also been programmed to account for the dependency of the hydrolysis reaction on the pH.
Also, because ester partitions into the oil phase and travels behind the water phase (i.e., Darcy velocity), performing two-phase flow would be necessary to highlight the significance of the pH dependency of the hydrolysis-reaction rate on the tracer profiles. For doing that, a multiphase Buckley-Leverett (BL) flow simulation is coupled with IPhreeqc, which is an open-source module of the PHREEQC geochemical package. Then, a California Turbidite SWCT test has been re-evaluated to verify the approach. At the end, the geochemistry of a reservoir with an almost weak resistance (high temperature and weak buffer capacity) against pH variation in the SWCT test has been studied using the geochemical-based approach. The results show that the variation of the hydrolysis rate with pH could affect mainly the tail edge of the predicted tracer profiles, and it could marginally affect the apex of the profiles; however, it might affect the interpreted value of the Sor measurement as the resistance against pH variation becomes weaker. In these conditions, adapting the SWCT-test designs (i.e., shut-in time and injecting lower concentration of ester) could diminish the pH variation.
The pH dependency of the hydrolysis-reaction rate is recommended for the numerical interpretation of the field SWCT-test data. The results of this study can be used to minimize the uncertainties of the SWCT tests and to improve the reliability of the Sor measurements.
Khan, Muhammad Faisal A. H. (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Al maskari, Shaymaa (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Kundu, Ashish (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Voleti, Deepak Kumar (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Al-Rawahi, Ali Salem (Abu Dhabi Co For Onshore Petroleum Operations Ltd)
The objective of this paper is to present a unique Petrophysical Grouping (PG) approach in a carbonate reservoir located in transition zone. It is very challenging, especially in Carbonate reservoirs, exist in transition zone, to establish PG definitions due to the complexities result from reservoir heterogeneities and diagenesis. Consequently establishing a suitable Saturation Height Function to match the Log derived Saturation is another challenge. In addition, the limited coverage of Mercury Injection based Capillary Pressure data (MICP) as compared to Routine Core analysis (RCA) data provides difficulties in establishing appropriate PG definition.
In first step the MICP data was used together with porosity/permeability to define distinctive groups. The PGs were further up-scaled using deterministic and Neural Network (NN) approaches. The best method was chosen by performing a test that compares the Washburn Pore Throat Radius (PTR) with the predicted PTR. To estimate a most representative log based permeability model, independent of water saturation a NN and Self-Organization Map methodologies were adapted. The limitations of MICP samples were handled by using an analog of a larger field with 100s of MICP samples. This was used to propagate the PGs to log domain by utilizing the permeability model.
Five PGs were defined using deterministic approach in which the best one is characterized having low displacement pressure, low irreducible water saturation, high pore throat radius and high porosity and permeability responses. Winland was shortlisted after testing other methods as the most applicable PG method in the reservoir as it provides the best correlation with lab PTR (94%) and the shape of WR35, consequently provides good match with computed Sw log and the shape of the PRT curve (
Balhasan, Saad (American University of Ras Al Khaimah) | Al Kandari, Bader (Kuwait Institute for Scientific Research) | Omar, Mohamed (Australian College of Kuwait) | Al-Otaibi, Jassim (Australian College of Kuwait) | Al-Shakhis, Hamad (Australian College of Kuwait) | Al Amer, Ali (Australian College of Kuwait)
The Water Alternating Gas flooding method aims to improve sweep efficiency during CO2 flooding. This study has screened three waterflooded sandstone reservoirs for CO2 injection to apply the Stalkup Model. An empirical correlation is derived from the Stalkup Model parameters Sorw, Sob, Sorm, and HCPVI to ease estimation of the recovery factor calculation process. The empirical correlation is called the WAG correlation. The hydrocarbon recovery percent calculations of the reservoirs after 1.2 HCPVI were as following; for reservoir (A), the Stalkup Model provided a recovery percentage of 10.00% against the WAG correlation value of 9.30%. In reservoir (B), Stalkup Model calculations gave 6.00% compared to 6.40% from WAG correlation. Finally, in reservoir (C) the calculation showed a 7.00% form Stalkup Model and 6.40% from WAG correlation. The estimated average error for the three reservoirs was 7.4%.
Olalotiti-Lawal, Feyi (Texas A&M University) | Onishi, Tsubasa (Texas A&M University) | Datta-Gupta, Akhil (Texas A&M University) | Fujita, Yusuke (JX Nippon Oil & Gas Exploration Corporation) | Hagiwara, Kenji (JX Nippon Oil & Gas Exploration Corporation)
We present a simulation study of a mature reservoir for CO2 Enhanced Oil Recovery (EOR) development. This project is currently recognized as the world's largest project utilizing post-combustion CO2 from power generation flue gases. With a fluvial formation geology and sharp hydraulic conductivity contrasts, this is a challenging and novel application of CO2 EOR. The objective of this study is to obtain a reliable predictive reservoir model by integrating multi-decadal production data at different temporal resolutions into the available geologic model. This will be useful for understanding flow units, heterogeneity features and their impact on subsurface flow mechanisms to guide the optimization of the injection scheme and maximize CO2 sweep and oil recovery from the reservoir.
Our strategy consists of a hierarchical approach for geologic model calibration incorporating available pressure and multiphase production data. The model calibration is carried out using regional multipliers whereby the regions are defined using a novel Adjacency Based Transform (ABT) accounting for the underlying geologic heterogeneity. To start with, the Genetic Algorithm (GA) is used to match 70-year pressure and cumulative production by adjusting pore volume and aquifer strength. Water injection data for reservoir pressurization prior to CO2 injection is then integrated into the model to calibrate the formation permeability. The fine-scale permeability distribution consisting of over 7 million cells is reparametrized using a set of linear basis functions defined by a spectral decomposition of the grid connectivity matrix (grid Laplacian). The parameterization represents the permeability distribution using a few basis function coefficients which are then updated during history matching. This leads to an efficient and robust workflow for field scale history matching.
The history matched model provided important information about reservoir volumes, flow zones and aquifer support that led to additional insight to the prior geological and simulation studies. The history matched field-scale model is used to define and initialize a detailed fine-scale model for a CO2 pilot area which will be utilized for studying the impact of fine-scale heterogeneity on CO2 sweep and oil recovery. The uniqueness of this work is the application of a novel geologic model parameterization and history matching workflow for modeling of a mature oil field with decades of production history and which is currently being developed with CO2 EOR.
den Boer, Lennert (Schlumberger) | Sayers, Colin (Schlumberger) | Gofer, Edan (Schlumberger) | Lascano, Maria (Schlumberger) | Walz, Milton (Schlumberger) | Dasgupta, Sagnik (Schlumberger) | Purdue, Gregory (Apache Corporation) | Goodway, William (Apache Corporation)
Rock fractures are of great practical importance to petroleum reservoir engineering because they provide pathways for fluid flow, especially in reservoirs with low matrix permeability, where they constitute the primary flow conduits. An example is the Midale reservoir, SE Saskatchewan, Canada. In such reservoirs, understanding the spatial distribution of natural fracture networks is key to optimizing production. Fortunately, the presence of fractures can be inferred from variations in reflection amplitude as a function of azimuth and incidence angle. This paper presents the application of a method for constructing a geologically realistic discrete fracture network (DFN), constrained by seismic amplitude variation with offset and azimuth (AVAz) data. The DFN realization is upscaled to compute the anisotropic permeability tensor, which is then compared with waterflood results.
Presentation Date: Monday, September 25, 2017
Start Time: 2:40 PM
Presentation Type: ORAL
Time-lapse acoustic impedance (AI) inversion for Weyburn oil field (southeastern Saskatchewan, Canada) is performed by combining the data from seismic records, well logs and velocities inferred during reflection seismic processing. The objective of time-lapse AI mapping in the field consists in constraining fluid migration during CO2 injection and enhanced oil recovery. The time-lapse AI is derived by a three-step procedure: 1) time-variant seismic calibration of the records from three available vintages of the dataset; 2) evaluation of the differential reflectivity and 3) derivation of the differential AI from differential reflectivity. Although applied to early stages of CO2 injection, the resulting differential AI images and time-shift images suggest indications of CO2 migration.
Presentation Date: Thursday, September 28, 2017
Start Time: 10:35 AM
Presentation Type: ORAL
Characterizing anomalies detected on seismic-generated attributes is crucial in interpreting any formation of interest. Consequently, a representative rock physics model is needed to determine the effect of petrophysical properties on the seismic response. The developed workflow presented in this paper utilizes differential effective medium theory, Hudson's model for cracked media, and Gassmann's fluid substitution equation for anisotropic rock to represent horizontal transverse isotropic (HTI) in a reservoir rock. The rock physics model provides the ability to predict vertical incidence velocity variation for the compressional and two principal shear wave components (fast and slow) due to changes related to mineralogy, porosity, water saturation, fracture density, and pressure at the target unit. The forward modeling process involves varying a single parameter over its anticipated range, then determining the density and compressional and shear velocities. Although the presented petrophysical workflow is applied to Ordovician Red River Formation within Cedar Creek Anticline in the Williston Basin, it can be extended to other formations with the need to modify certain assumptions.
Presentation Date: Tuesday, September 26, 2017
Start Time: 10:35 AM
Location: Exhibit Hall C/D
Presentation Type: POSTER