This paper studies the technical and economic viability of this EOR technique in Eagle Ford shale reservoirs using natural gas injection, generally after some period of primary depletion, typically through long, hydraulically fractured horizontal-reach wells. The Eagle Ford formation has produced approximately 2 billion bbl of oil during the last 7 years, yet its potential may be even greater. Using improved oil-recovery (IOR) methods could result in billions of additional barrels of production. Shale EOR Works, But Will It Make a Difference? The promise of getting 30% more oil production from shale wells has set off a race by companies trying to see if they can replicate what EOG has done.
Southwest Research Institute is adding a new facility to its capabilities in testing and evaluating subsea equipment and systems. This review of papers illustrates some of the innovative solutions used in the region. This paper focuses on a numerical-modeling analysis of the acid-gas-injection (AGI) scenario in carbonate HP/HT reservoirs, and presents the way in which AGI impacts asphaltene-precipitation behavior.
Flow assurance in the oil and gas industry refers to the systems put in place to guarantee uninterrupted profitable and sustainable flow of hydrocarbons from the reservoir to surface facilities and ultimately to refineries. Flow assurance challenges include: inorganic scale, asphaltene, wax, corrosion, hydrates, etc. Managing these challenges is becoming more complex because of development of fields under harsher conditions e.g. HPHT reservoirs, sour reservoirs, heavy oil; in addition to further implementation of EOR (gas injection, chemical, surfactant and polymer floods). Different engineering and chemical solutions can be put in place to manage these challenges. All cancellations must be received no later than 14 days prior to the course start date.
Temizel, Cenk (Aera Energy) | Balaji, Karthik (University of North Dakota) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Moreno, Raul (Smart Recovery) | Rabiei, Minou (University of North Dakota) | Zhou, Zifu (University of North Dakota) | Ranjith, Rahul (Far Technologies)
Due to complex characteristics of shale reservoirs, data-driven techniques offer fast and practical solutions in optimization and better management of shale assets. Developments in data-driven techniques enable robust analysis of not only the primary depletion mechanisms, but also the enhanced oil recovery in unconventionals such as natural gas injection. This study provides a comprehensive background on application of data-driven methods in oil and gas industry, the process, methodology and learnings along with examples of data-driven analysis of natural gas injection in shale oil reservoirs through the use of publicly-available data.
Data is obtained and organized. Patterns in production data are analyzed using data-driven methods to understand key parameters in the recovery process as well as the optimum operational strategies to improve recovery. The complete process is illustrated step-by-step for clarity and to serve as a practical guide for readers. This study also provides information on what other alternative physics-based evaluation methods will be able to offer in the current conditions of data availability and the understanding of physics of recovery in shale oil assets together with the comparison of outcomes of those methods with respect to the data-driven methods. Thereby, a thorough comparison of physics-based and data-driven methods, their advantages, drawbacks and challenges are provided.
It has been observed that data organization and filtering takes significant time before application of the actual data-driven method, yet data-driven methods serve as a practical solution in fields that are mature enough to bear data for analysis as long as the methodology is carefully applied. The advantages, challenges and associated risks of using data-driven methods are also included. The results of comparison between physics-based methods and data-driven methods illustrate the advantages and disadvantages of each method while providing the differences in evaluation and outcome along with a guideline for when to use what kind of strategy and evaluation in an asset.
A comprehensive understanding of the interactions between key components of the formation and the way various elements of an EOR process impact these interactions, is of paramount importance. Among the few existing studies on natural gas injection in shale oil with the use of data-driven methods in oil and gas industry include a comparative approach including the physics-based methods but lack the interrelationship between physics-based and data-driven methods as a complementary and a competitor within the era of rise of unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals.
Mandal, Dipak (Oil & Natural Gas Corporation Ltd) | Baruah, Nabajit (Oil & Natural Gas Corporation Ltd) | Jena, Smita Swarup (Oil & Natural Gas Corporation Ltd) | Nayak, Bichitra (Oil & Natural Gas Corporation Ltd)
Hydrocarbon gas injection into the reservoir is one of the most effective EOR processes. In case of a dipping and light oil reservoir, immiscible gas injection can give further impetus to the oil recovery. Since, average current gas saturation in the subject reservoir has become high due to depletion rendering water injection at this late stage is found to be ineffective, scope of gravity assisted immiscible gas injection as an alternative has been evaluated to assess its impact on reservoir pressure and ultimate recovery.
The present study pertains to a high permeable clastic light oil reservoir with reasonable dip, belonging to an old field of South Assam Shelf of India under production since 1990 with current recovery of 22% of STOIIP. The reservoir being undersaturated with no aquifer support, shows significant decline in reservoir pressure (260 ksc of initial pressure to current level of 50 ksc). Simulation study has been carried out on a fine scale geo-cellular model. Multiple realizations have been created considering combinations of oil producers and gas injection wells assigning varied rates to study the different development scenarios and impact on recovery improvement. The study indicates an incremental oil recovery of about 14% of STOIIP by immiscible gas injection.
Based on the study, immiscible gas injection has been initiated in the reservoir on pilot scale basis through two gas injectors with continuous monitoring. After gas injection during last one year, reservoir pressure increased about 25 ksc and consequently per well productivity also increased. Non-flowing well starts producing and currently sand is producing nearly 25% higher than earlier production before gas injection. Based on the encouraging result from pilot gas injection, decided to expand the process at field level and subsequently drilling of new oil producers after jacking up of reservoir.
The study has brought out that the gas injection into shallower portion of the reservoir yields better sweep efficiency to displace the oil to the deeper portion of the reservoir due to the gravity effects and hence, appropriate locales of the reservoir are targeted for additional input generation to augment the oil recovery.
Baruah, Nabajit (Oil & Natural Gas Corporation) | Mandal, Dipak (Oil & Natural Gas Corporation) | Jena, Smita Swarupa (Oil & Natural Gas Corporation) | Sahu, Sunil Kumar (Oil & Natural Gas Corporation)
This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.
Thapliyal, Anil (Oil and Natural Gas Corporation Ltd.) | Kundu, Sudeb (Oil and Natural Gas Corporation Ltd.) | Chowdhury, Suparna (Oil and Natural Gas Corporation Ltd.) | Singh, Deepika (Oil and Natural Gas Corporation Ltd.) | Singh, Harjinder (Oil and Natural Gas Corporation Ltd.)
Pressure maintenance by gas injection in gas cap is one of the well-established methods for improving the ultimate recovery. Gas injection in the crestal part of reservoir into the primary or secondary gas cap for pressure maintenance is generally used in reservoirs with thick oil columns and good vertical permeability and this process is called gravity drainage. This paper comprises methodology and results of study to evaluate the feasibility of gas injection in gas cap for maintenance of reservoir pressure and to envisage incremental oil gain of a mature offshore carbonate field located in western offshore of India.
Field has already produced more than 30% oil of its initial inplace volume. Water injection was started after 4 years of production and currently field is producing oil with 90% water cut. After one year of initial production phase the field producing GOR rose to two to three fold of its initial value mainly due to contribution of gas from gas cap. Depletion of gas cap gas made significant adverse impact on reservoir pressure and also fast pressure depletion from crestal part had allowed water breakthrough of injection and aquifer water to oil producers. At this stage to reduce the decline rate of wells for maximizing the future recovery without drilling of new wells and also without extension of existing infrastructure, the injection of gas in depleted small gas cap have been studied.
In order to evaluate the feasibility of gas injection in depleted gas cap and its overall impact on oil recovery, three aspects were seen. First the optimized quantity of gas injection and its sensitivity along with the number of gas injectors were decided through reservoir simulation. Therefore, suboptimal oil producers falling within gas cap area are chosen for conversion to Gas injectors. Secondly injection gas requirement for the process will be fulfilled partly through the recycling of produced gas and rest from free gas production from another pay of the same field. Finally it is examined that current existing facility of gas compression will sufficiently cater the additional requirement of gas compression. The process will have additional 10 to 11% contribution in future oil production.
The process of charging gas cap will provide additional support over ongoing water injection leading to a significant additional oil recovery by reducing the oil decline rate.
US unconventional resource production has developed tremendously in the past decade. Currently, the unconventional operators are trying many strategies such as refracturing, infill drillings and well spacing optimization to improve recovery factor of primary production. They are also employing big data and machine learning to explore the existed production data and geology information to screen the sweet spot from geology point of view. However, current recovery factor of most unconventional reservoirs is still very low (4~10%). A quick production rate decline pushes US operator to pursue gas EOR for unconventional reservoirs, lifting the ultimate recovery factor to another higher level. The goal of this work is to improve oil recovery by implementing gas Huff and Puff process and optimizing injection pattern for one of the US major tight oil reservoirs - Eagle Ford basin. Gas diffusion is regarded as critical for gas Huff and Puff process of tight oil reservoirs. Utilizing the dual permeability model, gas diffusion effect is systematically analyzed and compared with the widely used single porosity model to justify its importance. Transport in natural fractures is proved to be dominated recovery mechanism using dual permeability model. Uncertainty studies about reservoir heterogeneity and nature fracture permeability are performed to understand their influences on well productivity and gas EOR effectiveness. Moreover, three alternative gas injectant compositions including rich gas, lean gas and nitrogen are investigated in gas Huff and Puff processes for Eagle Ford tight oil fractured reservoir. The brief economic evaluation of Huff and Puff project is conducted for black oil region of the Eagle Ford basin.
Unconventional oil reservoirs such as the Eagle Ford have had tremendous success over the last decade, but challenges remain as flow rates drop quickly and recovery factors are low; thus, enhanced oil recovery methods are needed to increase recovery. Interest in cyclic gas injection has risen as a number of successful pilots have been reported; however, little information is available on recovery mechanisms for the process. This paper evaluates oil swelling caused by diffusion and advection processes for gas injection in unconventional reservoirs.
To accurately evaluate gas penetration into the matrix, the surface area of the hydraulic fractures needs to be known, and in this work, three different methods are used to estimate the area: volumetrics, well flow rates and linear fluid flow equations. Fick's law is used to determine the gas penetration depth caused by diffusion, and the linear form of Darcy's law is used to find the amount from advection. Then, with the use of swelling test information from lab tests, we are able to approximate the amount of oil recovery expected from cyclic gas injection operations.
During the gas injection phase, gas from the fractures can enter the matrix by both advection (Darcy driven flow) and diffusion. We estimate that over 200 million scf of gas can enter the matrix during a 100 day injection/soak period. Using typical reservoir and fluid parameters, it appears that 40% is due to diffusion and 60% is due to advection. Sensitivity analysis shows that these numbers vary considerable based on the parameters used. Analytical models also show that during a 100 day production timeframe, over 14,000 stock tank barrels (STB) of oil can be produced due to huff-n-puff gas injection.
Both gas injection and oil recovery amounts are compared to recent Eagle Ford gas injection pilot data, and the model results are consistent with the field pilot data.
By determining the relative importance of the different recovery mechanisms, this paper provides a better understanding of what is happening in unconventional reservoirs during cyclic gas injection. This will allow more efficient injection schemes to be designed in the future.
Two new Non-Intrusive Reduced Order Modelling approaches to estimate time varying, spatial distributions of variables from arbitrary unseen inputs are introduced. One is a generalization of an existing'dynamic' approach which requires multiple surrogate evaluations to model the solutions at different time instances, the other is a'steady-state' approach that evaluates all time instances simultaneously, reducing the local approximation error. The ability of these approaches to estimate the water saturation distributions expected during a gas flood through a 2D, dipping reservoir is investigating for a range of unseen input parameters. The range of these parameters has been chosen so that a range of flow regimes will occur, from a gravity tongue to a viscous dominated Buckley-Leverett displacement. A number of practically relevant model error measures were employed as opposed to the standard L2 (Euclidean) norm. The influence of the number and the structure of training simulations for the model was also investigated, by employing two simple experimental design methods. The results show that POD based NIROM approaches are prone to significant deviations from the true model. The main sources of error are due to the non-smooth variation of system responses in hyperspace and the transient nature of the flows as well as the underlying dimensionality reduction. Since the first two sources are properties of the physical system modelled it may be expected that similar problems are likely to arise independently of the interpolation method and the reduction process used.