Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
In its latest sale since financial restructuring in February, Linn Energy sold its Williston Basin properties to an undisclosed buyer for $285 million. The company entered the Bakken in early 2011 with the purchase of the assets from Concho Resources for $196 million. This deal brings Linn's year-to-date total sales agreements to more than $1.5 billion. The company's restructuring, the intent of which was to transition it from an upstream limited partnership to a growth-oriented E&P company, reduced its debt by more than $5 billion to a total of $1 billion. With the sale of the Jonah, South Belridge, and Salt Creek assets, the company eliminated all remaining outstanding debt.
This paper presents a new workflow for the simulation of in-situ combustion (ISC) dynamics. In the proposed method, data from kinetic cell experiments, depicting the combustion chemistry, are tabulated and graphed based on the isoconversional principle. The tables hold the reaction rates used to predict the production and consumption of chemical species during in-situ combustion.
This new method of representing kinetics without the Arrhenius method is applied on one synthetic and two real kinetic cell experiments. In each case, the new method reasonably captures the reaction pathways taken by the reacting species as the combustive process occurs. A data-density sensitivity study on the tabulated rates for the real case shows that only four experiments are required to capture adequately the kinetics of the combustion process. The results are, however, found to be sensitive to the size of the time step taken. The method predicts critical changes in the reaction rates as the experiment is exposed to different temperature conditions, thereby capturing the speed of the combustion front, temperature profile, and fluid compositions of a simulated combustion tube experiment.
The direct use of the data ensures flexibility of the reaction rates with time and temperature. In addition, the non-Arrhenius kinetics technique eliminates the need for a descriptive reaction scheme that is typically computationally demanding, and instead focuses on the overall changes in the carbon oxides, oil, water and heat occurring at any time. Significantly, less tuning of parameters is required to match laboratory experiments because laboratory observations are easier to enforce.
Saini, Dayanand (California State University, Bakersfield) | Wright, Jacob (California State University, Bakersfield) | Mantas, Megan (California State University, Bakersfield) | Gomes, Charles (California State University, Bakersfield)
A critical analysis of the key geological characteristics, completion techniques, and production behaviors of the Monterey Shale wells and their comparisons with analogous major US shale plays—namely, the Bakken and the Eagle Ford—may provide insights that could eventually help the petroleum industry unlock its full potential. The present study reports on such efforts.
The Monterey Shale is very young and geologically heterogeneous compared with the Eagle Ford and the Bakken. Oil viscosity in the Monterey Shale is significantly higher, and one can also notice that Monterey oil production has declined over the years. The Monterey Shale has a field-dependent completion strategy (pattern spacing and fracturing stage), while a horizontal, uncemented wellbore completion is common in the Bakken and the Eagle Ford. In the Monterey, nonhydraulically fractured zones of horizontal and hydraulically fractured wells appear to be making approximately equal contributions to the well’s cumulative production. The ongoing water-disposal operations in overlying injection zones, up to a certain extent, have affected the productivity of both types (long and short production histories) of wells. The geology also appears to have an effect on the production behaviors of horizontal and hydraulically fractured wells.
A preliminary economic analysis suggests that exploitation of the Monterey Shale is still a profitable venture. However, for sustainable development in a current price regime of USD 50/bbl of crude oil, it is necessary that production costs be reduced further. Also, compared with the Bakken and the Eagle Ford, the Monterey sits in regions of extremely high water stress (i.e., frequent occurrences of drought or drought-like conditions). However, oilfield-produced water associated with current steamflooding-based oil- and gas-production operations in the region as a base fluid suggests that it can potentially meet most of the water demand for future fracturing jobs. Also, combined use of a centralized water-management system; a less-costly, more energy-efficient, and high-capacity solar-powered desalination system; and a final sludge-management and/or residual-brine-disposal mechanism might assist the petroleum industry in managing flowback and produced waters while keeping water-handling costs low.
A combination of new enhanced-oil-recovery (EOR) methods for releasing the remaining oil from both nonfractured and fractured zones of horizontal wells and the use of oilfield-produced and recycled water for completing hydraulically fractured horizontal wells might prove to be a significant change for the future exploitation of California’s Monterey Shale resource, which is subject to the toughest hydraulic-fracturing regulations in the nation and is in a region of extremely high water stress.
Enhanced Oil Recovery (EOR) has been utilized in Trinidad and Tobago for over 50 years. Most projects so far have focused on thermal as well as gas injection along with the more conventional waterfloods. In spite of that, recovery factors are still relatively low and the country's oil production has been declining for some time. Surprisingly, given the progress in chemical EOR and in particular polymer flooding in the last 10 years, these processes have not been used in Trinidad and we suggest that it might be time to consider their application. Similarly, foam has been used extensively worldwide to improve performances of gas and steam injection but has not yet been used in the country.
The situation of EOR in Trinidad will be first reviewed along with the characteristics of the main reservoirs. Then the potential for the application of chemical-based EOR methods such as polymer, surfactant and foams will be studied by comparing the characteristics of Trinidad's reservoirs to others worldwide which have seen the applications of chemical-based EOR methods.
This review and screening suggests that there is no technical barrier to the application of all these EOR methods in Trinidad. Most reservoirs produce heavy oil and are heavily faulted, but polymer injection has been widely applied in heavy oil reservoirs as well as in faulted reservoirs before, and suitable examples will be provided in the paper. Similarly, these characteristics do not present any specific difficulty for foam-enhanced gas or steam injection. The main issue appears to be the identification of suitable water sources for the projects.
This paper proposes a new look at EOR opportunities in Trinidad using conventional methods which have not been used in the country. This will help reservoir engineers who are considering such applications in the country and hopefully will eventually result in an increase in the oil production in the future.
Models for steam or hot-water injection into a fractured diatomite or shale reservoir are developed from existing analytic models of energy transport and countercurrent imbibition.
Radial convective heat flow through a horizontal fracture system is modeled with conductive heat flow into the low-permeability matrix. The flow geometry approximates hot-fluid injection into a five-spot pattern. Recovery mechanisms accounted for in the models include capillary imbibition and thermal expansion. Temperature dependence of viscosity and interfacial tension (IFT) are included in the imbibition estimate. Laboratory data are needed to quantify the magnitude of the imbibition mechanism, which is usually the primary contributor to oil recovery. Reservoir properties representative of either the Belridge Diatomite or the Antelope Shale, two giant fractured oil reservoirs, are used for the model forecasts. Currently, however, only temperature-dependent imbibition data for diatomite reservoirs are available.
The steamflood model has been partially validated against a large-scale project in the Belridge Diatomite. By use of public-domain information, a reasonable comparison was obtained between the model and the field project during a 4-year injection period. Comparison with conventional thermal simulation was also performed, and it indicated reasonable agreement with the steamflood analytical model.
The models have been used to determine the key factors determining the success of thermal recovery in fractured, low-permeability reservoirs. Steam injection is shown to be superior to hot-water injection in heating the matrix. Key factors enhancing recovery include reduced fracture spacing, increased matrix permeability, and increased injection temperature. Model results indicate that steamflood recoveries of more than 40% of the original oil in place (OOIP) may be achieved by injection in diatomite containing light oil. Application to diatomites containing heavy oil also shows good performance. Successful application in diatomite reservoirs is forecast to be possible in the current low oil-price environment. Economic application in fractured shales, assuming similar imbibition behavior as in diatomites, would require a higher oil price because of the higher well costs and lower oil content relative to diatomite projects.
Because of the significant volumes of remaining oil in place (OIP) in both the diatomite and shale reservoirs, the application of thermal enhanced oil recovery (EOR) to these resources represents the logical next step in steamflood development.
Temizel, Cenk (Aera Energy) | Salehian, Mohammad (Istanbul Technical University) | Cinar, Murat (Istanbul Technical University) | Gok, Ihsan Murat (Istanbul Technical University) | Alklih, Mohamad Y. (ADNOC)
With the advances in data-driven methods, they have become more widely-used in analysis, predictive modeling, control and optimization of several processes. Yet, as it is a relatively new area in petroleum industry with promising features, the industry overall is still skeptical on use of data-driven methods as it is a data-based solution rather than traditional physics-based solutions. In this sense, in order to shed light on the background and applications in this area, this study comparatively evaluates one of the methods used in waterflood surveillance and optimization called capacitance-resistance model illustrated on two types of mature fields with high and low-perm characteristics.
Data-driven methods serve as a robust tool to turn data into knowledge. Historical data generally has not been used in an effective way in analyzing processes due to lack of a well-organized data where there is a huge potential of turning terrabytes of data into knowledge. A capacitance-resistance model is built to identify the well connectivities between the wells and then carry that knowledge to better reservoir management through optimization of injection and production in two different sets of data.
In CRM modeling, analysis of injection/production data at associated injectors and producers reveals the connectivities and further optimization leads to optimum injection values. Steps and the methodology of building a CRM model using real data is illustrated to exemplify the whole process in a comparative way between two mature reservoirs. We introduce the concept of application of spatial constraints in terms of injection-producer maximum influence radius to accelerate and improve the solution where knowledge of radius of influence for an injector is known by historical data and experience.
The theoretical and practical information is supported with mature field examples to investigate the factors affecting the performance of vertical wells in tight and intermediate-permeability reservoirs along with the outline of the major challenges and how to solve them. This study also illustrates the challenges of application of CRM on a tight reservoir in the order of 0.1md and comparison of the application of the method on a more intermediate-perm reservoir. Field data used in this study is from publicly available, open access source, Division of Oil, Gas & Geothermal Resources (DOGGR) website - http://www.conservation.ca.gov/dog
Thermohydromechanical effects can have significant impacts on the operations of heavy oil and geothermal fields. This motivates the use of accurate reservoir simulators in field development planning. Previously, simulation using continuous Galerkin methods was examined. However, these methods can experience difficulty in convection-dominated flow problems. Consequently, the discontinuous Galerkin method was considered as an alternative. The discontinuous Galerkin method's literature suggested the need to state a generalized, single-phase thermohydromechanical formulation to clarify previous work. This paper states this generalized formulation and performs a poromechanical benchmark of uniaxial compaction in FEniCS using the discontinuous Galerkin method. Additional work on extension to multiphase flow and the incorporation of thermal effects is needed.
Compaction-induced casing damage, particularly adjacent to reservoir boundaries, has been observed in many fields. As part of mitigation planning for potential casing collapse due to reservoir compaction, expensive numerical models are often employed to quantitatively assess casing strain under simulated reservoir conditions. In order to simplify casing deformation analysis and reduce analysis time, the current study was initiated to quantify the effects of depletion magnitude, rock compressibility, borehole orientation, casing diameter-to-thickness ratio (D/t ratio) and grade on compaction-induced casing deformation using finite element modelling (FEM). The model results allowed an empirical equation to be derived to predict casing strain that is sufficiently accurate for engineering applications.
The objective of the study was achieved by building a series of 3D FEM models to systematically simulate the deformation of casings cemented perfectly within a horizontal reservoir that underwent up to 8.3% compaction due to depletion. To capture the pattern of casing strain variation adjacent to the reservoir boundaries, the simulations were run over a range of borehole deviations (0°, 22.5°, 50°,67.5° and 90°). For each borehole deviation, casing D/t ratios of 8.14, 19.17 and 32.67 and grades of 40 ksi, 90 ksi and 135 ksi were defined to evaluate their impact on casing strain variations.
The FEM models show that casing deformation adjacent to reservoir boundaries is accommodated by radial expansion and axial shortening in vertical wellbores, while the deformation is characterized by bending in deviated wellbores. The maximum strain adjacent to reservoir boundaries varies systematically, but nonlinearly with each variable evaluated. The maximum strain increases with reservoir compaction strain, i.e. increases with rock compressibility and depletion, but decreases with increasing hole deviation. Both casing D/t ratio and grade affect casing strain, but their effects are secondary. In general, the maximum strain is greater for casings with smaller D/t ratios and higher grades at any given borehole deviation and compaction strain. The variation of the maximum casing strain with compaction strain can be described by a power law. Both its constant and exponent are functions of borehole deviation, casing D/t ratio and grade.
Because of the complexity of borehole-reservoir geometry and casing plastic behavior, there is no analytical solution available to estimate compaction-induced casing strain adjacent to reservoir boundaries. Numerical models may be used to predict the casing strain, but the numerical analysis is time consuming and requires specialist knowledge. The equation proposed from this study is sufficiently accurate compared to numerical models in terms of casing strain prediction, but provides a much simpler and quicker analysis. In addition, the study provides insight on the variation of casing strain with the major controlling factors, leading to a more complete understanding of compaction-induced casing deformation.
In its latest sale since financial restructuring in February, Linn Energy sold its Williston Basin properties to an undisclosed buyer for $285 million. The company entered the Bakken in early 2011 with the purchase of the assets from Concho Resources for $196 million. This deal brings Linn’s year-to-date total sales agreements to more than $1.5 billion. The company’s restructuring, the intent of which was to transition it from an upstream limited partnership to a growth-oriented E&P company, reduced its debt by more than $5 billion to a total of $1 billion. With the sale of the Jonah, South Belridge, and Salt Creek assets, the company eliminated all remaining outstanding debt.