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.
The relationship between produced gas and flowback/produced water is important for evaluating shale gas well performance; however, it is not fully understood yet due to complex flow mechanisms and interactions / feedback among various geoscience and engineering controls. Further investigation would provide valuable insight to adjust development plans to achieve optimal well/regional economic production.
In this study, an auto-updated nonlinear model method was applied to evaluate the relationship between water and gas in different spatial and temporal domains and to understand the micro-scale flow mechanisms from macro-scale data. Fracture-fluid flowback data in the dataset are water produced within one month, following a fracture treatment (exclusive of well shut-in time), and the produced water were 1 to 3 years. 114 wells from the Marcellus Formation in northwestern West Virginia were selected to investigate the relationship between fracture-fluid flowback and one month gas production in different spatial domains (wet and dry gas regions). 67 Marcellus wells in Lycoming County, Pennsylvania were selected to study the relationship between produced water and gas production across different time periods ranging from one to three years. The results indicate that the relationship between gas and fracture-fluid flowback in the wet gas region is positive while negative in the dry gas region. WGR (water gas ratio) is high (>9 bbl/mmcf) during the 1st-year which indicated water be carried out through displacement and leveled off at 3 bbl/mmcf after the 1st-year, indicating evaporation is the primary mechanism for water production. This study analyzed the relationship between gas and water production under different geological conditions and time periods and offers new insights on gas and fracture-fluid/produced water flow mechanisms in shale gas reservoirs.
Waterflood in low permeability carbonate reservoirs (<50 mD) leaves behind a substantial amount of oil. Alkali-surfactant-polymer (ASP) floods can improve oil recovery from these reservoirs by lowering the interfacial tension (IFT); however, there are several challenges such as polymer injectivity, divalent ions, geochemical interactions, pore-scale heterogeneity, and oil-/mixed-wettability. This paper addresses the first two challenges: polymer transport in low permeability carbonate cores and surfactant interaction with formation brine during ASP floods. Since polymer injection in low permeability carbonate cores is challenging, polymer transport in low permeability carbonate cores was studied. Shearing of high molecular weight polymers and successive filtration treatment were performed to reduce the polymer size distribution. Single phase polymer corefloods were performed to study the transport of treated polymers and identify the optimum pretreatment. Phase behavior experiments and aqueous stability experiments were performed to develop ultralow IFT surfactant formulations with a reservoir crude oil. ASP corefloods were performed in oil-wet low permeability limestone rocks. The oil recovery, pressure drop, effluent ionic composition, effluent viscosity and effluent surfactant concentrations were measured. Polymer hydrodynamic radius must be much smaller than the pore throat radii for the polymers to be transported. Mercury porosimetry data should be studied before polymer selection. Shearing and successive filtration can be used to reduce the hydrodynamic radii of polymers. This preprocessing worked with the HPAM polymer used in this study for the Edwards Yellow Limestone, but not for Texas Cream Limestone. An ultralow IFT ASP formulation can be developed with a formation brine with a significant amount of divalent ions by using a chelating agent. Tertiary ASP injection increased the cumulative oil production to 77% in a field core and 87% in an outcrop core. The adsorption of the anionic surfactants was limited to 0.4 mg/gm of rock in the core floods. UTCHEM simulations showed good agreement with lab coreflood experiments.
Ibrahim, M. (Apache Corporation) | Pieprzica, C. (Apache Corporation) | Vosburgh, E. (Apache Corporation) | Dabral, A. (Apache Corporation) | Olayinka, O. (Apache Corporation) | Larsen, S. (Apache Corporation)
Horizontal drilling accompanied with Hydraulic fracturing makes the unconventional reservoir a viable addition to worldwide production. Hydraulic fracturing of a well is the largest cost when evaluating total well expense. Therefore, understanding the fracture performance is fundamental to the success of a shale well. The two main factors controlling a shale horizontal wells performance is completion design and reservoir quality. The completion efficiency depends on factors such as well spacing, stage spacing, cluster spacing, fluid volume, proppant type and volume, injection rate, type of fracture fluid and gas price.
There are many techniques used to evaluate the hydraulic fracture performance. Some include post fracture analysis, tracer analysis, micro seismic analysis, rate transient analysis, production log analysis, fiber optics data and pressure transient analysis.
This paper presents the integration of completion data, petrophysical data, fluid sample analysis, mini-frac analysis, and flowback data in matching long term buildup data. More than 6 months of data was collected for one of the unique shale gas condensate wells during the appraisal stage of an area. The analysis showed the effect of liquid drop out and phase segregation in the flow regimes.
Also, this paper presents a different analytical model used to match the actual buildup data. The resulting model is used in building a reservoir model to forecast performance for the well.
Barite is one of the most common weighting materials used in drilling fluid for deep oil and gas wells. Consequently, the main source of solids building the filter cake is the weighting material used in drilling fluids ‘Barite particles’. Barite is insoluble in water and acids such as HCl, formic, citric, and acetic acids, as well as the barite has low solubility in chelating agent such as Ethylene Diamine Tetra Acetic Acid (EDTA).
The present study introduces a new formulation to dissolve the barite filter cake using converters and catalysts. Barite can be converted to barium carbonate at high pH medium using combination of potassium hydroxide (KOH) and potassium carbonate (K2CO3) solution. Then HCl acid can be used to dissolve the barium carbonate. Another solution is to use high pH EDTA chelating agent and potassium carbonate as a catalyst/converter in one step. The removal formulation also contains polymer breaker (oxidizers). The three components of the new formulation are compatible and stable up to 300°F. Solubility tests were conducted using industrial barite particles with size ranged from 30 to 60 micron. The solubility experiments were carried at 300°F for 24 hours. Different concentrations of catalyst were added to select the optimum concentration. The designed formulation was examined to remove filter cake formed by Barite drilling fluid using High Pressure High Temperature cell (HPHT).
The result of this study showed that the barite removal efficiency of new formulation reached to 87 % in water base mud and 83 % in oil base mud. The solubility test results presented that the solubility of barite particles in 0.6M EDTA was 62 % in 24 hours at 300°F. Adding potassium carbonate catalyst to the 0.6M EDTA solution the increased the solubility of barite to 90 wt. % in 24 hours. The use of converting agents increased the barite solubility from62% to 90% in EDTA. The EDTA was compatible with the polymer breaker (oxidizer) so the filter cake removal will be in single stage. The oxidizer concentration used was 10 wt%, potassium carbonate concentration was 10 wt% and EDTA concentration was 0.6M. The new formulation achieved 85% filter cake removal in both oil-based and water-based drilling fluids. In oil base mud a water wetting surfactant, mutual solvent, and emulsifier should be added to the formulation to remove the oil. In this study, two solutions were proposed to remove the barite filter cake and barite scale from oil and gas wells at different conditions. The first one is by using HCl acid after converting the barium sulfate to barium carbonate using high pH medium such as KOH and K2CO3. Then HCl can easily remove the barium carbonate. The second method is to create the high pH medium by using the removal fluid itself which is EDTA chelating agent in addition to potassium carbonate as converter.
Many completions require some sort of pack to prevent fines migration associated with the high production rates necessary for economic recovery. Traditional evaluation of these pack completions has generally been accomplished using a combination of pressure analysis, material balance calculations, and basic logging information, often including the use of radioactive tracers. Radioactive tracers introduce significant hazards relating to health, safety, and the environment, and therefore are under strict regulations. This paper presents a new alternative pack-evaluation technology which eliminates these radioactivity-related issues.
The new technique utilizes a recently introduced non-radioactive tracer containing a taggant material with a high thermal neutron capture cross-section. This tagged proppant can also be used as, or mixed with, conventional gravel or frac packing materials prior to downhole placement. The non-radioactive taggant is detected using standard pulsed neutron capture (PNC) logging tools, with detection based on the high thermal neutron absorptive properties and/or capture gamma ray spectral properties of the tagged pack material relative to other downhole constituents. The tagged pack material is indicated from: (1) changes in after-pack PNC detector count rates relative to corresponding before-pack count rates, (2) increases in PNC formation and borehole component capture cross-sections (Σfm and Σbh), and/or (3) increases in the computed elemental yield of the neutron-absorbing tag material, derived from the observed PNC capture gamma ray energy spectra. This technology has been successfully employed in induced fracturing operations in over 200 wells to determine fracture height, and in many situations also indicates relative fracture width. By further optimizing the concentration of the tag material in the proppant and the time windows utilized for PNC data processing for pack applications using Monte Carlo software (MCNP5), the resulting non-radioactive pack tracer (NRPT) technique can now not only evaluate gravel packs, but also fracture height behind the casing/gravel pack at the same time. Moreover, enhancements to this technique have also been developed to eliminate the before-pack log in some situations. As a result, these recent developments significantly simplify and shorten the logging procedure, and therefore reduce operational costs.
This paper begins with a brief review of prior published MCNP5 modeling data on gravel pack and frac-pack evaluation, and then discusses recent additional modeling data utilized in NRPT taggant concentration optimization, utilizing the borehole geometry of the well in the field log example in the paper. The effectiveness of the new NRPT technology is then demonstrated with the field example, which has only after-pack logs. In the field log evaluation, the natural gamma ray log, silicon activation log, borehole sigma log, formation sigma log, and gadolinium (the NRPT taggant) yield log are all analyzed. The most suitable logs and log combinations for evaluating gravel pack and fracture height were identified based on the comprehensive analysis, and quantitative evaluations for gravel pack and fracture height were obtained. This new technique is especially useful in evaluating onshore and offshore pack completions where the issues and hazards associated with the use of radioactive tracers can be significant and in situations where periodic monitoring of the condition of the GP is important. Time monitoring is impossible with radioactive tracers due to the short half-lives of the tracers being used.
Chen, Rongtao (Tianjin Branch, CNOOC Ltd.) | Su, Yanchun (Tianjin Branch, CNOOC Ltd.) | niu, Chengmin (Tianjin Branch, CNOOC Ltd.) | Wang, Qingbin (Tianjin Branch, CNOOC Ltd.) | Shi, Xinlei (Tianjin Branch, CNOOC Ltd.) | Zhang, Jianmin (Tianjin Branch, CNOOC Ltd.) | Wang, Feilong (Tianjin Branch, CNOOC Ltd.) | Qin, Runsen (Tianjin Branch, CNOOC Ltd.)
Through the comprehensive analysis of the data related to cores, logging and seismic, the author holded that there were two kinds of sedimentary systems in the study area, which were braided river deposits and meandering river deposits. According to the sequence stratigraphy method of fluvial facies proposed by Catuneanu et al, we established sequence stratigraphic framework in the Guantao formation of south gentle slope belt, Huanghekou Sag. It was divided into 2 third-order sequences, named as SQGU and SQGL, each of the third-order sequences contains a high accommodation systems tract (HAST) and a low accommodation systems tract (LAST). On this basis, the author summarized the sedimentary sequence evolution characteristics in the Guantao formation of south gentle slope belt, Huanghekou Sag. In the period of LAST in the SQGL, there were mainly composed of braided river facies in the study area, main developed multistage compound sand body. In the period of HAST in the SQGL, there were mainly composed of meandering river facies in the study area, main developed isolated point bar sand body and a high proportion of flood plain mud. The evolution characteristic of the SQGU was similar to the SQGL. Because of the accommodation space of the SQGU was at a high level, the grain size of sandstone and the percentage of sandstone are smaller than SQGL.
It is generally accepted that it was mainly composed of braided river facies in Guantao formation of Huanghekou Sag, difficult to form oil and gas reservoir due to lack of mudstone cap rock. The exploration of Guantao formation has not attracted enough attention. Through this analysis, the author thinked that two sets of meandering river deposition can provide partial sealing and created conditions for oil-gas accumulation in the Guantao formation of south gentle slope belt, Huanghekou Sag. Under the guidance of this research, we have obtaineda certain oil and gas discovery in the study area.
Surfactant flooding is a common enhanced oil recovery technique that has been researched for its scientific potential, but inhibited by its economics. This method relies on greatly reducing interfacial tensions between phases, allowing the displacement of previously immobile oil. For this process to succeed on an industry scale the high chemical cost involved must be outweighed by the increased oil production. One way to decrease the cost of surfactant chemicals, is to ensure the slug sized used is no larger than necessary. Accounting for the physical mixing in a compositional simulator plays a large role in determining the optimum slug size and success of the project.
Mixing occurs when the surface area between concentration gradients expands, increasing diffusion. In reservoir simulators, the amount of numerical dispersion can alter greatly depending on the model structure. To achieve a model reflecting a physical case, the mixing influencing surfactant concentrations must match the mixing occurring in the reservoir. The more heterogeneous a reservoir is, the more physical mixing will occur as the area of contact increases significantly with length traveled. Because dispersion is scale dependent, matching the physical amount of dispersion by varying the gridblock size can be challenging. As a numerical model is upscaled, the physical mixing decreases while the numerical dispersion associated with the grid increases.
To show the effects of the changing gridblock scale and heterogeneities, two dimensionless parameters were used to test various models for their optimum surfactant-polymer slug size. Both one and two-dimensional models were created in UTCHEM to simulate a surfactant injection process by altering one of the dimensionless parameters, and observing the optimal slug size. A matured water flood was followed by chemical flooding. The optimal was found using the incremental efficiency of the surfactant, taking the incremental oil recovered divided by the mass of chemical injected. The incremental efficiency curves display a single optimum for each case, which closely tie to the economic potential of the process. With knowledge from core flood experimentation, when looking to apply at field scale, it is vital to account for the difference in the mixing effects. This work could result in a better understanding of the optimal surfactant volume needed, greatly reducing chemical costs.
The placement of proppants in hydraulically fractured wells determines the conductivity of fractures and productivity of shale wells. In slickwater farcturing, proppants are often not transported deep into fractures. In this paper, proppant transport in foam-based fracturing fluid is visualized in a laboratory-scale fracture slot. Effect of parameters like foam quality, proppant loading, and injection rate are systematically investigated. Additionally, a CFD based model is developed to simulate the lab experiments by assuming the foam as a single-phase non-Newtonian fluid. Experiments show that dry foams (80% quality) can carry proppants between the lamellas with little vertical settling. A complex flow pattern is developed at the bottom of the slots in dry foams due to protrusion of foam fingers into proppant laden foam flow. Proppants are not carried very well in wet foams (70% quality) and form a proppant bed near the injection well. This is due to severe drainage of surfactant solution from the foam as it moves through the fracture. CFD simulation of proppant transport agrees approximately with the experimental observations for the dry foams. The simulation results do not agree with the experimental observations for the wet foams. The assumption of treating foams as a continuum non-Newtonian fluid is not valid for wet foams where drainage of surfactant solution is significant.
In recent years, there has been a proliferation of massive subsurface data from instrumented wells. This places significant challenges on traditional production data analysis methods for extracting useful information, in support of reservoir management and decision-making. Additionally, with increased exploration interest in unconventional shale gas reservoirs, there is a heightened need for improved techniques and technologies to enhance understanding of induced and natural fracture characteristics in the subsurface, as well as their associated impacts on fluid flow and transport.
The above challenges have the potential to be addressed by developing Big Data analytic tools that focus on uncovering masked trends related to fracture properties from large volumes of subsurface data, through the application of pattern recognition techniques. We present a new framework for fast and robust production data classification, which is adapted from a real-time face detection algorithm. This is achieved by generalizing production data as vectorized 1-D images with pixel values indicating rate magnitudes. Using simulated shale gas production data, we train a boosted binary classification algorithm which is capable of providing probabilistic predictions. We demonstrate the viability of this approach for identifying hydraulically fractured wells which have the potential to benefit from restimulation treatment. The results show significant improvements over existing type-curve based approaches for recognizing favorable candidate wells, using solely gas rate profiles.