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NITEC LLC announces the spinoff of its Multi-Objective, Many Agents inverse solution technology for enterprise-level decision intelligence under a new company, AIMOO LLC.  After years of solving complex reservoir engineering challenges, we’ve developed powerful technology that’s now available as a standalone product (globalMOO™) to solve multi-objective problems outside of the realm of reservoir engineering.   

globalMOO™ inversely solves complex numerical models, including black-box AI models, enabled by many agents that mimic the inference process used by human subject matter experts.  This unique product is used in optimizing multiple objectives that cannot be simplified to a single performance index, as well as in calibrating complex numerical models to known outcomes.  Naturally, the trained agents can be deployed at the edge for near real-time decision support. 

The new company will be managed by Dr. Tuba Firincioglu, while maintaining her existing position as the Managing Director of NITEC LLC.  Dr. Firincioglu said; “We’re driven by the belief that organizations should have access to a powerful and trustworthy decision intelligence tool. With our globalMOO™ inverse solution product, you can have both.” 

To learn more, visit globalMOO.com and explore how this breakthrough technology can transform your optimization challenges.  NITEC LLC continues to provide industry-leading reservoir engineering consultancy. 

Chet Ozgen, Director, NITEC LLC 

View us on Product Hunt

NITEC’s Dr. Tuba Firincioglu has won the Regional Reservoir Description and Dynamics Award for the SPE Rocky Mountain North America Region, recognizing significant achievements or contributions to the advancement of petroleum engineering in the area of the technical discipline. The award will be presented in the fall of 2020.

“Impact of Temporary Well Shut-ins on Unconventional Reservoir Performance”

July 15-17

San Antonio

Visit them online

Joseph Mozelewski from NITEC team will give a presentation on “Impact of observation wells on inventory verification for Aquifer Storage”.  Please visit NITEC’s table to learn more about our Gas Storage Decision Support Solutions.

“A reservoir simulation-oriented investigation into large-scale conductive fractures in the Osage shale oil reservoir.” Matt Freeman, Richard MacDonald, Steve Geetan, Tuba Firincioglu.

“An Integrated Reservoir Modeling Case Study to Simulate Multi-stage Hydraulically Fractured Horizontal Wells, based on Seismic, Petrophysical and Geological data for Pinedale Tight Gas Fluvial Reservoir.” M. Gaddipati, T. Firincioglu, E. LaBarre, Y. Yang, D. Wahl, P. Clarke, A. Long and C. Ozgen
“Overcoming the Limitations of SRV Concept” , M. Gaddipati, C. Karacaer, C. Ozgen, and T. Firincioglu

“A Simulation Case Study of Gas Injection Pilot in Eagle Ford”, Brandon Rogers, Murphy Oil Corp, Basar Basbug, NITEC LLC, Tuba Firincioglu NITEC LLC, Chet Ozgen, NITEC LLC.

“A Methodological Workflow for Assessment and Design of a Huff-n-Puff Hydrocarbon Gas Injection Pilot Test as an EOR Technique for Eagle Ford Shale Oil Reservoirs”, Amanda Baldwin, Leo Lasecki, David Mohrbacher, Lee Porter, Brian Nicoud, Grant Taylor, Jose Zaghloul, Chesapeake Energy, Basar Basbug, Tuba Firincioglu, NITEC LLC, Reza Barati, University of Kansas.

Chet Ozgen attended the workshop as a Session Chair.  Jairo Corredor from Devon Energy gave a presentation on “Importance of Integrated Geo-Mechanics in Shale Re-Frac Modeling”, which includes a study that Devon performed with NITEC.

We are very excited to have Dr. Erdal Ozkan as part of NITEC team for a year. Dr. Ozkan will work on integration of information obtained from RTA/PTA to numerical simulation models.

Please come and visit us at the upcoming URTec (Unconventional Resources Technology Conference) which will be held in Denver, Colorado on July 22-24 2019.

Our booth number is 433.

Check them out online

 

 

 

 

 

Based on a 9 well history matched model in Eagle Ford, feasibility of huff and puff gas injection for a full field development was investigated. The operational pressure range, the injection schedule, and the injection rate were optimized to achieve a successful huff and puff pilot in this area to confirm the feasibility and maximize the knowledge.

Reservoir Study of the Largest Oil Field in Argentina – A Two Reservoir 2200 Well Simulation Model”, Claudio Marcelo Fonseca, Gustavo Fernandez, Repsol-YPF, Tuba Firincioglu, Chet Ozgen, Alejandro Albertoni, NITEC LLC, SPE ATCE, September 2004. SPE 90952

Abstract

Reservoir Study of the Largest Oil Field in Argentina – A Two Reservoir 2200 Well Simulation Model

This paper describes the processes incorporated during the simulation study of the Chihuido de la Sierra Negra Field in Argentina, which is presently the largest oil field in the country. The field was discovered in 1968, and an aggressive water injection program was started in 1995. So far the oil production from this field is 65 million cubic meters and the water injection is 158 million cubic meters.

The field has two separate stacked reservoirs that are structurally complex with different fault systems and fluids. Both reservoirs are highly compartmentalized with each compartment having different water-oil contact. The upper reservoir is composed of 6 isolated geologic layers, with each being different depositional environments (sand bars, dunes, fluvial channels, etc.). The presence of unconformities and volcanic intrusions further complicate the reservoir communication and plays an important role in flow behavior.

Currently, the field has 734 production wells with commingled production from both reservoirs and the isolated zones with in the upper reservoir. Approximately 1250 injection strings are currently injecting water.

The purpose of this study was to provide a detailed reservoir characterization to optimize recovery and to create a simulation model with predictive capability that can be used in improving field management. To achieve this purpose a 900,000 cell simulation model was constructed.

This paper will discuss some of the challenges encountered during the history matching of the field model. The identification of the compartment boundaries and their associated water oil contacts (57 contacts) required the development of a new consistent approach. This method provided significant accuracy and time savings over the traditional approach of iterating between history matching and reservoir characterization. The overwhelming volume of data and the volume of simulation results for 2200 well strings required special considerations for pre- and post-processing. New tools were needed to quickly modify the simulation arrays and review all the wells in an efficient and timely manner. As the history matching progressed many additional practical tools were developed. This paper will discuss the significance of these innovations and tools to achieve a successful history match in a timely manner.

“Soft Computing Algorithms Accelerate and Improve The History Matching Process: Elk Hills, 29R Reservoir”, Tuba Firincioglu, Chet Ozgen, Alejandro Albertoni, NITEC LLC, Bill O’Brien, Radu Girbacea, Occidental of Elk Hills, SPE Western Regional/AAPG Pacific Section/GSA Cordilleran Section Joint Meeting, Anchorage, May 2006. SPE 100489

Abstract

Soft Computing Algorithms Accelerate and Improve The History Matching Process:

Elk Hills, 29R Reservoir

This paper presents the application of soft computing (virtual intelligence) techniques1 to a reservoir simulation history matching problem. The objective of this work was not to automate the history matching process as has been discussed by others2-7, but rather to provide the engineers with the necessary information to improve the speed and quality of their results.

Through the use of virtual intelligence techniques history match error (mismatch – the difference between calculated and observed flow and/or pressure) is correlated to variations in individual history match parameters like porosity, permeability, and so on. An objective function that describes the criteria to minimize the mismatch is defined.

This technology always finds the global minimum associated with the objective function. The technology provides multiple solutions that satisfy any error criteria, and produces related statistical information. The technology can handle continuous or discrete history match parameters.

In this paper we discuss the successful application of this technology to a simulation study of a complex, fractured, porcelanite oil reservoir (Elk Hills-29R, Bakersfield, California). This field has 28 years of history with 42 production wells. A dual porosity formulation was necessary to properly model the fractured nature of the reservoir. Successful history match results obtained in a short period of time for this field showed the accuracy and practicality of this unique history matching technology.

NITEC evaluated the impact of 3rd party E&P operations outside the storage boundary on this storage fields gas recovery-zone in the cap rock above the aquifer storage field. The storage and gas-recovery operations had been stable for many years until recent E&P activity in the surrounding areas was targeting the shale caprock. NITEC was able to confirm that the E & P activity was negatively impacting the storage operations and developed a counter-strategy to protect the stored gas in the recovery zone.

“A Finite Difference Approach to Modeling Geomechanics in Hydraulic Fracturing.”, Petunin, V.V., NITEC LLC, 47th US Rock Mechanics/Geomechanics Symposium, San Francisco, CA, June 23-26, 2013. ARMA 13-460

Abstract

A Finite Difference Approach To Modeling Geomechanics In Hydraulic Fracturing

The ability to both model the growth of a fracture system from a hydraulic fracture treatment and its closure over time due to pressure depletion is critical to understand and improve hydraulic fracture methodology. If the Stimulated Rock Volume (SRV) is pre-determined by the engineer and flowback water is discounted during history matching using a conventional reservoir simulator, the actual hydraulic fracturing treatment has no impact on the model. A holistic approach that incorporates the entire life of the well is key to history matching hydraulically fractured wells. The new reservoir simulation technology presented here contains novel features that allow for such a complete match of hydraulically fractured wells. Field reported fracture fluid volumes are injected at the measured rates, stage by stage, in order to generate the SRV. If the hydraulic fracture design is changed it will change the generated SRV. This technique has been applied to wells in the Wolfcamp, Three Forks, and Bakken shale oil fields. The quality of the history match has been higher than what was possible using pre-existing technology.

NITEC’s client needed decision support on deciding between refracing existing wells and drilling infill wells in the same area. NITEC provided analysis of both options by utilizing a five well simulation model that is calibrated for reservoir and geomechanical parameters in the area.

NITEC developed a complex reservoir simulation involved two aquifer storage formations and an oil production – gas recovery formation above the main storage zone. This field was old with vintage well logs and data records. The objective for the study was to determine the volume of gas migration into the recovery formation over the past 50 years and provide operations strategy to minimize future gas migration.

A prolific oil field in Wyoming with significant primary and secondary recovery was evaluated for bypassed secondary and tertiary oil potential. The natural fractures in the formation and the historical water injection resulted in little additional secondary oil recovery potential. Accordingly, the remaining oil in place was found to be insufficient to warrant an economically viable CO2 injection program. Other tertiary recovery processes are under consideration.

A verification of the process was carried out for a thermal recovery process – insitu upgrading of hydrocarbons. Thermal simulation correctly correlated with laboratory results and a U.S. field evaluation considered Huff-n-Puff and continuous injection.

“Fracture Characterization for Integrated Studies: A new approach and its applications,” Cetin Ozgen, Tuba Firincioglu, Alejandro Albertoni, NITEC LLC, SPE ATCE, Denver, October 2003. SPE 84413

Abstract

Fracture Characterization for Integrated Studies: A new approach and its applications

This paper describes a new approach for fracture characterization by integrating all of the available data, geology, petrophysics, core analysis and production data. Our approach in fracture characterization produces normalized distributions for fracture presence and anisotropic connectivity. The normalized information is directly imported into the 3D flow simulator, where it can be scaled during sensitivity analyses. This fast approach enables the testing of the effect of the fracture indicators and their influence on the limits of fracture presence.

In this paper, the successful applications of this fracture characterization technology to a complex fractured volatile oil reservoir with an aquifer (Sen Field, Mexico) and a fractured helium gas storage field (Bush Dome Reservoir, Texas) are presented. The results of these integrated studies are provided as proof of concept. Successful history match results obtained in a short period of time for these fields show the efficiency of the integrated fracture characterization technique.

An integrated reservoir study was carried out on a near depleted oil field in Wyoming discovered in 1916 with over 700 completions. The simulation model history match indicated substantial remaining oil in place. Extended black-oil simulation of CO2 WAG and continuous CO2 injection processes indicated significant tertiary oil recovery potential. Full-field development is in the planning stages.

“OMEGAPLUS: An Enhanced Gas Storage Reservoir Simulator”, C. Ozgen, C. Weinstein, A. Modine, SSI, Y. Shikari, GRI, AGA Operating Section Proceedings, Nashville, 1991.

NITEC’s client needed proper optimization for well spacing and frac size. Through a 6 well simulation model, NITEC provided the optimum spacing and frac size for different benches of the producing formations. Optimum frac sizes and spacing were different for different benches. The client increased capital efficiency by differentiating the completion and spacing practices among the different benches.

NITEC’s client needed to improve its completion practices to recover more oil in Eagle Ford. Simulation study led to a design that improved the Infill of an infill well performance such that the new well produced more than the original parent well’s total production within months. The optimization was based on a 4 well history matched simulation model.

“Use of Capillary Pressure Data and Log Calculated Water Saturation for the Characterization of Dual Porosity, Dual Permeability Systems”, C. Ozgen, T. Firincioglu, NITEC LLC, H. Araujo, Andina S.A., LAPEC, Caracas, April 1999. SPE 53860

Abstract

Use of Capillary Pressure Data and Log Calculated Water Saturation for the Characterization of Dual Porosity, Dual Permeability Systems

This paper describes a simple method to divide the effective porosity values that can be calculated from log analysis into two flow media (fracture and matrix) pore volumes for use in numerical simulation models. The division of the porosity is based on the assumption that the total porosity of the system is made up from two contributing rock types or lithofacies that have distinct pore size and/or pore size distribution such that they can be represented by different capillary pressure functions. This assumption is applicable to the non-fractured as well as to the fractured systems.

When the method is used for the fractured systems, the fracture is typically represented by a zero capillary pressure value (gravity segregation). The matrix has its own laboratory measured capillary pressure curve. Based on a predetermined water-hydrocarbon contact and using the difference between the density gradients of the fluids, the capillary pressures of the two media are converted to theoretical water saturation profiles as a function of TVD. Next, at each depth point, the two extreme theoretical water saturation values are compared to the log calculated water saturation measurements. Based on a simple weighting algorithm, the contributions of the fracture and matrix media to the total porosity are calculated. The results can be upscaled to the numerical simulation grid block size or be used in geostatistical approaches.

Using the developed technique, we have built simulation models for two different reservoirs. One of the models represents a fractured system, while the other represents a non-fractured system with two distinct rock types. For the non-fractured reservoir, the dual porosity formulation enabled us to accurately upscale the capillary pressure functions by default. The approach and the results of the numerical models are presented in the body of this paper.

“Unraveling Minimum Liquid Yields from Variable PVT and Production Data in the Woodford using EOS”, Caner Karacaer, NITEC LLC; Leslie Thompson, Cimarex Energy Co., Tuba Firincioglu, NITEC LLC, Unconventional Resources Technology Conference held in San Antonio, Texas, USA, July 20-22, 2015.

Abstract

URTeC: 2154623

Unraveling Minimum Liquid Yields from Variable PVT and Production Data in the Woodford using EOS

This paper introduces a novel workflow to map minimum liquid yield (OGR) values of the Woodford unconventional reservoir to generate a trend that indicates a compositional variance from a lean-to a rich in-situ gas system.

The objective of the workflow is to estimate the minimum yield based on the initial yield produced from a well. For this purpose, a unified Equation of State (EOS) model was generated using the recombined fluid samples of nine Woodford wells. EOS tuning was focused on Constant Composition Expansion (CCE), Constant Volume Depletion (CVD), and flash liberation of separator liquid experiments. Discrepancies between initial producing OGR and reported OGR of recombined surface fluids from the lab reports were resolved by modifying the recombination ratio of the liquid and gas phases. An iterative procedure was used to calculate the appropriate surface recombination ratio utilizing a compositional reservoir simulator.

A compositional depletion simulation study was conducted to replicate the CVD experiments and to calculate the liquid yield values of each well for various abandonment pressures. It was shown that the minimum liquid yield value produced in the field is affected by the critical oil saturation as well as the phase behavior of the fluid. Increasing critical oil saturation decreases the minimum liquid yield. The reported minimum liquid yield values in this study are considered as the minimum liquid values that can be reached theoretically for this particular fluid system.

A correlation between the initial producing OGR and the simulated minimum yield was established. Using the correlation the minimum liquid yield for wells without any fluid sample can be estimated from the initial producing yield and can be mapped. Choosing the well locations with higher liquid yield potential will add economic value to the reservoir development project. The engineer can also design the most appropriate operational practices for the expected liquid yields.

NITEC’s client needed proper optimization for well spacing and frac size. Through modeling, NITEC provided the optimum spacing and frac size for different benches of the producing formations. Three reservoir simulation models were generated to create an optimum solution that would represent multiple regions in the area. Improved understanding of the reservoir and the spacing optimization that takes into account the interference supported the client’s decision making on capital spending.

Limited performance and wellbore data in a recent oil discovery in India suggested the existence of a natural fracture system. Seismic, wellbore, and performance data, along with NITEC’s unified capillary pressure technology were used to confirm and describe the vertical and areal fracture distribution. Field development is being planned accordingly.

“New Methods to Determine Pressure Losses in Gas Flow Strings”, T. Firincioglu, Istanbul Technical University, 11th Petroleum Congress of Turkey, Ankara, April 1996.

“OMNET: An Integrated Surface Facilities/Reservoir Simulator”, C. Weinstein, A. Modine, C. Ozgen, SSI, Y. Shikari, GRI, AGA Operating Section Proceedings, Kansas City, 1992.

NITEC conducted a detail field study to evaluate the gas storage potential of a deep depleted oil carbonate reservoir. The study included geology and petrophysics analyses to create a reservoir characterization model for a detailed reservoir simulation study. The simulation model history matched the original depletion period, matching oil, water and gas rates and pressure observation data. Due to the depth and anticipated operating pressure for the storage operations, a compositional model was required to accurately predict the miscible interactions between the gas and remaining oil and the resulting oil production. The results were used to design the liquid handling requirements for the surface facility.

“Three-phase Flow and Wettability Effects in Triangular Capillaries”, T. Firincioglu, NITEC LLC, Martin J. Blunt, Stanford University, Dengen Zhou, Chevron, Colloids and Surfaces A: Physicochemical and Engineering Aspects 155 (1999) 259-276.

Abstract

Three-phase Flow and Wettability Effects in Triangular Capillaries

We performed a series of two and three-phase flow experiments in capillary tubes with equilateral triangular cross-sections. We measured the flow rates of oil and water in water-wet tubes and compared them with predictions using an empirical theoretical expression for fluid conductance. Our results are consistent with a free boundary condition at the gas/liquid interface, and with a no-flow boundary at the oil/water interface, when water is stationary, and a condition between a no-flow and a free-boundary when oil and water flow simultaneously. By studying oils with different spreading coefficients we measured the circumstances when oil layers form, and we compared the results with a simple geometric argument for oil layer existence. We also studied flow in uniformly oil-wet tubes. Overall, the work verifies and calibrates theoretical expressions for fluid conductance and layer formation that can be inputted into pore level network models to predict macroscopic properties, such as relative permeability. We illustrated this approach by using our work to interpret three-phase relative permeability experiments on sandpacks.

“Geologic Storage of Carbon Dioxide and Enhanced Oil Recovery II: Co-optimization of Storage and Recovery”, A. R. Kovscek, M. D. Cakici, Department of Petroleum Engineering, Stanford University, Energy Conversion and Management, 46(11-12), 1941-1956 (2005)

Abstract

Geologic Storage of Carbon Dioxide and Enhanced Oil Recovery II: Co-optimization of Storage and Recovery

Geologic sequestration of carbon dioxide (CO2) in oil and gas reservoirs is one possibility to reduce the amount of CO2 released to the atmosphere. Carbon dioxide injection has been used in enhanced oil recovery (EOR) processes since the 1970s; the traditional approach is to reduce the amount of CO2 injected per barrel of oil produced. For a sequestration process, however, the aim is to maximize both the amount of oil produced and the amount of CO2 stored. It is not readily apparent how this aim is achieved in practice. In this study, several strategies are tested via compositional reservoir simulation to find injection and production procedures that “co-optimize” oil recovery and CO2 storage. Flow simulations are conducted on a synthetic, three dimensional, heterogeneous reservoir model. The reservoir description is stochastic in that multiple realizations of the reservoir are available. The reservoir fluid description is compositional and incorporates 14 distinct components. The results show that traditional reservoir engineering techniques such as injecting CO2 and water in a sequential fashion, a so-called water-alternating-gas process, are not conducive to maximizing the CO2 stored within the reservoir. A well control process that shuts in (i.e. closes) wells producing large volumes of gas and allows shut-in wells to open as reservoir pressure increases is the most successful strategy for co-optimization. This result holds for both immiscible and miscible gas injection. The strategy appears to be robust in that physics simulations employing multiple realizations of the reservoir model all confirmed that the well control technique produced the maximum amount of oil and simultaneously stored the most CO2.

This light-oil field in Venezuela with a thin oil rim and overlying gas condensate zone was characterized and simulated. Understanding reservoir performance required identification and characterization of asphaltene deposition in the oil rim and detailed simulation of over 100 wells with multiple production strings. Simulation predictions provided new completion alternatives and workovers to improve future oil recovery.

“Inferring Interwell Connectivity Only from Well-Rate Fluctuations in Waterfloods”, A. Albertoni, Larry W. Lake, University of Texas, SPE/DOE Improved Oil Recovery Symposium, Tulsa, April 2002. SPE 75225

Abstract

Inferring Interwell Connectivity Only from Well-Rate Fluctuations in Waterfloods

This paper presents a practical technique to quantify communication between wells in a reservoir using only production and injection rate data. The technique combines a constrained multivariate linear regression analysis with diffusivity filters to provide information about permeability trends and the presence of transmissibility barriers. The method was developed and tested using a numerical simulator and then applied to a waterflooded field in Argentina. The simulation results indicate that the connectivity between wells is described by coefficients that only depend on geology and the relative position between wells; they are independent of injection/production rates. The results of this work can be used to improve the performance of an existing waterflood by suggesting how well patterns might be changed or managed. They could also be used to model flow in the reservoir.

NITEC conducted an integrated reservoir study in a complex fluvial sand gas storage field to provide operations strategies for controlling gas migration between the main storage structure and a small low productivity structure and improving deliverability and working gas capacity. The project resulted in 10 new wells which increased deliverability by 75 MMCF/d and increased working gas by 10 BCF and provided a strategy to eliminate the gas migration.

NITEC investigated the inference impact on well performance and parent-child relationship for a major oil company. Well spacing per section was optimized based on the injected frac volume. The optimum time to introduce the child well after parent production, minimum vertical and horizontal distance from the parent well to minimize the parent’s influence on the child well production were determined. All the optimization was based on a calibrated (history matched) seven well physics-based simulation model in Permian.

Based on an 8 well calibrated simulation model in Eagle Ford, the feasibility of huff and puff gas injection for a full field development was investigated. The actual pilot gas injection was part of the calibration. The performance under different operational scenarios including injection rates, injection/production sequence, and scheduling were investigated and reported to support the management’s decision.

“Thermodynamics of Multiphase Flow in Unconventional Liquids-Rich Reservoirs.”, Firincioglu, T., NITEC LLC, Ozkan, E., Colorado School of Mines, Ozgen, C., NITEC LLC., SPE Annual Technical Conference and Exhibition, San Antonia, TX, October 8-10, 2012. SPE 159869

Abstract

Thermodynamics of Multiphase Flow in Unconventional Liquids-Rich Reservoirs

The average pore size in currently producing unconventional, liquids-rich reservoirs is estimated to be less than 100 nm. At this nano-pore scale, capillary and surface disjoining force interactions (like van der Waals, structural, and adsorption) play an important role on phase behavior that is not considered in conventional PVT studies. In this paper, a comprehensive discussion of thermodynamics required to adequately model phase behavior that can impact multiphase flow in unconventional, liquids-rich reservoirs is presented. Three oil samples from different unconventional reservoirs are used to generate results. The impact of confinement manifests itself in the form of reduction (suppression) of the liquid pressure that the first bubble can form when compared to the bulk fluid measurements that are conducted in PVT cells. It is shown that the suppression of the bubble-point pressure impacts saturated portion of the liquid formation volume factor and extends the undersaturated portion of the curve. The gas composition is different for each supersaturation level and the gas is composed of lighter components as the supersaturation (bubble point suppression) increases

NITEC’s client needed an evaluation of different spacing in Bakken and Three Forks development for exploration purposes. Using publicly available data around the exploratory acreage a representative simulation model was calibrated for reservoir and geomechanical parameters. This information was migrated to the exploratory area by changing the reservoir characterization accordingly. Further sensitivities to optimize spacing and landing for this new area were performed.

NITEC’s client needed guidelines to build proper size compressors to be utilized in huff and puff operations at Eagle Ford. Using models created at different depths containing different oil types, operational ranges (pressure and injection rate) of possible huff and puff operations were determined for proper compressor design.

“New Method for the Quantification of the Traveling-Valve Leakage Using Dynamometer Techniques”, A. Albertoni, YPF, Petrotecnia, Instituto Argentino del Petróleo, October 1994.

NITEC represented the buyer in technical assessment meetings as part of our evaluation process. This field was comprised of two dome shape lobes connect through a syncline. The key issue for this field was to assess the connective between the two domes and additional base gas requirements as well as evaluate reservoir containment risks due to unmapped adjacent areas. NITEC provided the client with valuable insight into the stratigraphic complexities in this region.

NITEC’s client needed a quick evaluation of a field that they were planning to bid on. They used NITEC’s model to understand and evaluate the upside potential by infill drilling and assess the uncertainties associated with the project. The analysis provided by NITEC helped the client’s decision to bid or not on the prospect.

“A Simulation-Based Process to Predict the Impact of Hydraulic Fracture Parameters on EUR: A Tight Gas Example”, C. Yetkin, T. Firincioglu, NITEC LLC, A.M. Haney, Encana, SPE Eastern Regional Meeting, Lexington, KY, October 3-5, 2012. SPE 161350

Abstract

A Simulation-Based Process to Predict the Impact of Hydraulic Fracture Parameters on EUR: A Tight Gas Field Example

This study develops a process that determines the critical hydraulic fracture parameters and quantifies their impact on the EUR by combining reservoir simulation with probabilistic analysis methods. The process is verified by a real field case example in a tight gas reservoir. The final product can be applied to other unconventional reservoirs to ultimately maximize revenues by planning superior fracturing operations and optimizing well spacing.

A detailed dual-porosity, 3 section reservoir model was created and history matched to model the flow mechanism. A fine layered (2-3ft) geostatistical model was utilized in simulation without upscaling. The dual porosity formulation enabled the simulation model to represent the hydraulic fracture – matrix interaction properly so that the flowback and formation water production could be matched also.

During the history matching phase, the parameters that control the impact of hydraulic fractures on the recovery were identified as follows:

Matrix-fracture exchange: this parameter represents the complexity of the fractures and is controlled by the surface area created during hydraulic fracturing.
Fracture conductivity: this is effectively the permeability of the hydraulic fracture
Half-length: this parameter impacts the extent of the hydraulic fracture, therefore the amount of matrix that has been accessed.

Job size: The size of the water volume injected during the hydraulic fracturing process
In this work, an internal proprietary technology that creates a response surface for the combination of the parameters defined above was utilized. The history matched simulation model was automatically modified to create the necessary cases to calculate a multi-dimensional response surface. The created response surface was then used to do Monte Carlo simulations to create P10 to P90 probabilities of the total gas production (EUR).

The results of the study allowed us to understand not only the mechanisms operating in the reservoir being studied but also the required hydraulic fracture parameters (ranges) to achieve a given EUR of a specific probability. The same algorithms were then be used to predict the future performance of other well spacing patterns and hydraulic fracture job sizes.

“Determination of Gas Separation Pressure and Stages Using a Numerical Simulator”, P. Gentil, H. Bloise, A. Albertoni, YPF, Boletín de Información Petrolera (BIP), YPF S.A., November 1995.

“Integrated Compositional Surface-Subsurface Modeling for Rate Allocation Calculations”, Gerardo Lobato-Barradas, Pemex E&P, K. Dutta-Roy, consultant, Agustin Moreno-Rosas, Pemex E&P, Cetin Ozgen, T. Firincioglu, NITEC LLC, SPE International Petroleum Conference and Exhibition, Villahermosa, February 2002. SPE 74382

Abstract

Integrated Compositional Surface-Subsurface Modeling for Rate Allocation Calculations

An integrated fully compositional model describing the reservoir, wellbore and surface facilities was implemented and used to allocate the oil and gas production of 72 wells from six different fields. The model was used to simulate all the operational changes occurred in the twenty-year operating life-cycle of the fields, sharing common production and separation facilities.

NITEC conducted a detailed evaluation of this complex gas storage field with oil production. The field was a faulted anticline resulting in partial compartmentalization impacting the communication from two portions of the gas bubble and the downslope oil leg. The valuation was dependent on confirming well productivity/deliverability rates and increased oil production with the storage expansion. NITEC was able to identify key areas of uncertainty regarding the production claims as well as regulatory issues that were used in the client’s valuation model.

NITEC history matched a dual-porosity simulation model for this 40 BCF naturally fractured and faulted carbonate gas storage reservoir. The study required developing a new reservoir characterization for the nature fractures using NITEC fracture characterization technology. The model was used to evaluate the deliverability benefits from in-fill wells vs. well workovers vs additional compression. (58 wells, 28.2 BCF working gas, 660 MMcf/d)

“Full Field Fracture Characterization and Compositional Dual Porosity Modeling of a Complex Fractured Volatile Oil Reservoir – Sen Field, Mexico”, R. Perez Herrera, Pemex E&P, C. Ozgen, T. Firincioglu, Peter Colonomos, NITEC LLC, Second Simulation Meeting, Buenos Aires, November 2002.

Abstract

Full Field Fracture Characterization and Compositional Dual Porosity Modeling of a Complex Fractured Volatile Oil Reservoir – Sen Field, Mexico

Sen Field is a highly faulted and fractured volatile oil reservoir. In terms of connectivity, it is highly anisotropic, and the level of anisotropy varies areally in the field. The matrix is very tight and it is mostly filled with water. The matrix contribution to oil production is not significant. The fluid storage and flow are governed by the fractures and vugs that are present in the field. Considering the factors that influence the oil recovery, the determination of the fracture distribution and connectivity became the primary focus of the reservoir characterization effort.

The necessary data (outcrop studies, FMI logs, etc) required by the existing commercial fracture characterization software was not available for the Sen Field. Therefore an alternative method was developed for fracture characterization. The method utilizes the available data and provides a reliable fracture characterization that can be used in the reservoir simulation directly. Based on the fracture characterization work, a dual-porosity compositional simulation model was built to simulate the flow behavior of the field.

Since the reservoir pressure remained above the bubble point pressure, the observed static well pressure and the water cut data were used as the control points for the history matching exercise. An excellent history match was obtained especially considering the steep water cut profiles that are historically observed in the wells.

In this paper, we present the fracture characterization technology that was developed and the key history matching parameters of the numerical simulation model.

“Simplified Oil-Water Relative Permeability Expressions Accounting for Hysteresis in the Imbibition Cycle”, C. Ozgen, D.M. Chang, H.H. Haldorsen, Sohio Petroleum Company, Reservoir Characterization (1986) 373-392

Abstract

Simplified Oil-Water Relative Permeability Expressions Accounting for Hysteresis in the Imbibition Cycle

A method which permits the calculation of wetting phase relative permeability with knowledge only of the pore size distribution index (λ) and of a trapping constant (C) has been formulated. The non-wetting phase, relative permeability correlations are derived in a manner similar to that of Land in his original work. The proposed method makes it possible to account for spatial variations in rock type since relative permeabilities for individual lithologies vary as λ and C vary.

Hysteresis in oil-water relative permeabilities is of major concern in many multi-phase flow scenarios. The early work done by Land addressed this problem, but the complicated equations introduced have been of little help for the practicing engineer. Further attempts to describe this phenomenon with simplified expressions did not fundamentally address the behavior of the wetting phase relative permeabilities.

The practical method proposed in this paper has been adapted for use in numerical studies of the Prudhoe Bay Field. The correlations have adequately described reservoir behavior in areal studies and in matching displacement efficiencies inferred from a fiberglass cased observation well where repeat dual induction logs to determine changing water saturations can be measured. The correlations also compare favorably with laboratory results.

The improved correlations have made it possible to make relative permeabilities lithology dependent without invoking heuristic relative permeability averaging techniques. This improved reservoir description has increased our confidence in simulation results.

NITEC completed a storage optimization study for a large storage field in Kentucky, initially with over 150 old vertical wells, 135 BCF Total gas and 730 MMcf/d peak deliverability. The history matched model was used to evaluate replacing old vertical wells with horizontal wells, surface gathering system improvements (12 branched/looped lines), and additional compression power. Currently, the field has 13 horizontal wells, increased deliverability to 1,030 MMcf/d, and improved working gas to total gas efficiency.

“An Excess-Bubble-Point-Suppression Correlation for Black Oil Simulation of Nano-Porous Unconventional Oil Reservoirs.”, Firincioglu, T., Ozgen, C., NITEC LLC, Ozkan, E., Colorado School of Mines, SPE Annual Technical Conference and Exhibition, New Orleans, LA, September 30- October 2, 2013. SPE 166459

Abstract

An Excess-Bubble-Point-Suppression Correlation for Black Oil Simulation of Nano-Porous Unconventional Oil Reservoirs

The average pore size in unconventional, liquids-rich reservoirs is estimated to be less than 100 nm. At this nano-pore scale, capillary forces play an important role on phase behavior that is not considered in conventional PVT studies. Confinement on phase behavior of black-oil fluids manifests itself as bubble point pressure suppression, extension of the undersaturated portion of the formation volume factor curve, and alteration of the equilibrium gas composition. Studies show that the magnitude of the bubble point suppression is more than the capillary pressure and may amount to hundreds of psi. These phenomena can be modeled through compositional solution of the phase behavior at differing gas- and oil-phase pressure values that are due to capillary pressure. However, black-oil simulators cannot perform the compositional phase behavior calculations to estimate the total bubble point suppression due to confinement. In this study a correlation that expresses the bubble point pressure suppression as a function of the capillary pressure and the solution gas oil ratio (Rs calculated through conventional PVT which is the input in black oil simulator) was developed, such that it can be used as a simulation model input. The correlation data was based on three unconventional oil samples evaluated at different saturation pressures and compositions. To use the correlation, a modified black oil simulator that can handle the PVT data at different oil- and gas-phase pressure values is required. The source code of the black oil simulator used in this study was modified to include the total bubble point suppression into the PVT calculations. The impact of the confined phase behavior on flow was quantified through simulation runs. The results showed that the grid blocks with different capillary pressure values reach the bubble point at different times. During depletion, the grid blocks with higher capillary pressure values remained in undersaturated conditions longer, impacting the gas production and pressure profiles.

NITEC developed the reservoir characterization from old vintage well logs for this 65 well 75 BCF gas storage field which was input to the simulation model. The model was successfully history match and provided deliverability predictions for 15 in-fill wells increasing storage capacity to 96 BCF working gas with peak rate of 1,230 MMCF/d

“Impact of Temporary Well Shut-ins on Unconventional Reservoir Performance”
Authors: Dr. Tuba Firincioglu, Director Unconventional Reservoir Projects, and
NITEC’s Senior Reservoir Engineers:
(Dr. B. Basbug,  Dr. M. Freeman, V. Petunin, Dr. H Sarak),
NITEC LLC Research White Paper, May 2020

Abstract

This paper summarizes the expected reservoir response after long shut-in periods, and the impact on oil production for different unconventional reservoir basins.  The analysis discussed in this paper is based on NITEC’s experience modeling unconventional reservoirs and our understanding of how these resources work.  The  results are based on new simulation forecasts from NITEC’s extensive modeling experience with the major UC reservoirs .  The results are generated using Ridgdeway Kite’s 6X simulator.    The figures are generated using NITEC’s Lynx post processor.  The findings represent example responses for typical wells within each basin.  They may not apply to every well and every situation as they are merely examples and do not represent any particular location, asset or well.

Recent reduction in oil demand due to the COVID-19 pandemiImpact of Temporary Well Shut-ins on UC Reservoir Performance_20200521c will shape the oil industry in the coming months.  Storage shortages in the US put an extra strain on the WTI, which resulted in negative spot prices and futures in the late May oil price.  Under these circumstances, oil companies responded by temporarily shutting-in production wells to prevent losing money on each barrel of oil they sell.  The length of these temporary shut-ins is not known and will depend on how quickly the world recovers from the pandemic and when the demand for oil returns.

When the market returns to more normal conditions and the shut-in wells are opened for production, the question will be how will these wells perform after the long shut-in periods.  This issues needs to be addressed on two fronts: Reservoir and Operations.  Once the reservoir response is understood, operational changes can be implemented to address the possible negative impact on production from the long shut-in period.

[Click here for full paper] 

NITEC’s client needed evaluation on the relationship between GOR behavior and water production and water saturation in Permian. NITEC explained the relationship between water saturation, wettability, and GOR through modeling. This knowledge impacted the understanding of the reserves and long term production behavior.

NITEC developed a complex reservoir simulation for the world’s only helium gas storage field. The storage operation is located in a natural fracture and faulted carbonate formation. NITEC performed an integrated reservoir characterization (stratigraphy, structure, petrophysics, and seismic) as well as using its fracture characterization technology to develop the dual-porosity 4 component composition simulation model. The model successfully history match 78 years of operations with over 3,500 pressure points and 7000 gas composition points. The model is still in use today for prediction the helium recovery as the storage field is being depleted and abandoned.

A highly fractured and faulted reservoir in Mexico with an active aquifer was successfully characterized by NITEC’s in-house technology. Reservoir simulation resulted in the identification of highly productive zones which were confirmed by drilling.

A unified EOS model was generated for Woodford shale using 20 samples covering from dry gas to gas condensate.

NITEC performed a detail field study to determine the gas storage potential of a depleted oil fluvial sand reservoir. The study included geology and petrophysics analyses to create a reservoir characterization model for a detailed reservoir simulation study. The simulation model history matched the original depletion period, matching the oil and gas rates and pressure data. The optimal development required groups of 3 horizontal wells with gas injection used to sweep the remaining oil into the center production well, ultimately increasing the reservoir pore volume available for gas storage as well as recovering additional oil volume. The initial test development wells were drilled, proving the validity of the reservoir characterization, but economic conditions tabled the project.