Basak Kurtoglu

The Effect of Osmotic Pressure on Improve Oil Recovery from Fractured Shale Formations

Shale swelling during drilling is attributed to osmotic pressure, where low-salinity water enters the shale pores to cause swelling. Low-salinity water injected into high-salinity Bakken formation could similarly enter the matrix pores to displace oil by counter-current flow observed in core experiments. As a result, we believe, low-salinity water can potentially enhance oil recovery from oil-wet Bakken formation. In this paper, we report experimental and numerical modeling studies we conducted to evaluate the potential of lowsalinity waterflooding in Bakken. For laboratory experiments, we used horizontal core plugs drilled parallel to the bedding plane. The mathematical included osmotic pressure, gravity and capillary effects. In the mathematical model, the osmotic pressure mass transfer equations were calibrated by matching time-dependent salinities in a published laboratory osmotic pressure experiment. We also modeled oil recovery for a Bakken core using our osmotic pressure mass transport model. The results indicate that osmotic pressure promotes counter-current flow of oil from both the water-wet and oil-wet segments of the core. Introduction Osmosis is the transport of water molecules flow from low-salinity side of a semi-permeable membrane to the high-salinity side to equalize the concentration of the dissolved salts. This causes an increase of pressure on the higher-salinity side, called osmotic pressure (π), Fig. 1. In subsurface environment, high-clay shale sediments can behave as a semi-permeable membrane, thus causing osmotic water transport (Kemper; 1961, Milne et al.; 1964, Young and Low; 1965, Chenevert; 1970, Olsen; 1972, Greenberg et al.; 1973, Marine and Fritz; 1981, Fritz; 1986, Van Oort et al.; 1994, and Keijzer; 2001).

Geologic Characterization of a Bakken Reservoir for Potential CO2 EOR

Copyright 2013, Unconventional Resources Technology Conference (URTeC) This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 12-14 August 2013. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper without the written consent of URTeC is prohibited.

Evaluation of Bakken Performance Using Coreflooding, Well Testing, and Reservoir Simulation

The success of oil production in North Dakota Bakken should be credited to advanced completion and stimulation techniques. The abundance of data on well production, core analyses and flooding, geologic reservoir characterization, and pressure transient testing has enhanced reservoir evaluation. Understanding matrix and fracture contribution to daily oil production is the key to identifying reservoir drivers affecting the lifelong well productivity. In this paper, we will present an application of core flooding, mini-frac and pressure build-up tests, decline curve analysis and reservoir simulation history matching to achieve reliable long-term reservoir performance predictions. This approach could lead to developing an integrated workflow for determining the performance drivers in the greater Bakken. Information presented in this paper includes well performance data from several Bakken fields, displacement results on selected cores, mini-frac and pressure transient analyses, and history matching using decline curve analysis and numerical simulation. Specifically, the matrix permeability from core measurements is on the order of 10 md while the permeability from well testing is on the order of 10 md. The latter represents the combined contributions of micro-fractures and matrix permeability. Reservoir simulation also shows that a single-porosity system, using only the matrix permeability from the core analysis, is not sufficient for matching well production performance without having a secondary permeability and porosity (micro-fractures). The dual-porosity nature of the reservoir was confirmed by a long-term pressure build-up test. Introduction The Bakken Formation in North Dakota consists of three informal members -an upper and lower black organic-rich shale separated by a dolomitic sandstone-siltstone. The overlying Lodgepole Formation consists of a dense limestone and calcerous shale with minor amounts of chert and anhydrite while the underlying Three Fork Formation consists of shale, dolostone, siltstone, sandstone, and minor occurrences of anhydrite (Fig. 1). The Upper and Lower Bakken shales are the potential petroleum source rocks for both the Bakken and Three Forks Formations. Depositional environments interpreted for the Bakken Formation have ranged from a marine swamp with restricted circulation caused by the prolific growth of organic matter to an offshore marine environment (LeFever, 1991). The average porosity in the North Dakota Bakken is about 5% to 6% and matrix permeability is ultra-low compared to a typical conventional reservoir. However, the existence of interconnected micro-fractures in the matrix provides the permeable flow path in the reservoir as concluded from Bakken mini-DST data results (Kurtoglu, et al., 2012). The North Dakota portion of the Bakken was estimated to contain 167 billion barrels of oil with 2.1 billion barrels technically recoverable with the current technology based on the state of North Dakota’s report in 2008. Considering the continuous improvement in stimulation and completion technology as well as increased understanding of the reservoir characteristics, it is anticipated that we should be able to improve both the primary oil production and oil production by enhancing drainage of oil from the matrix and fractures by improved and enhanced oil recovery techniques.

Evaluation of Long-Term Performance of Oil Wells in Elm Coulee Field

Unconventional oil reservoirs, such as Bakken, have gained considerable interest in recent years because they have become a great resource to produce oil and gas to meet the energy needs of North America. Performance prediction from these tight reservoirs is a challenge because of the complexity of reservoir flow, well completion, and fracture stimulation techniques. Elm Coulee field, in Bakken, is an example of such unconventional reservoirs and is located in Richland County, Montana. The field was drilled using both vertical and horizontal wells, but in recent years the use of horizontal wells has become the standard practice. The objectives of this study were: (1) evaluate the long-term (7 to 10 years) performance of horizontal wells in Montana Elm Coulee, (2) develop a better understanding of how to predict the long-term performance of younger Bakken fields in North Dakota based on the Elm Coulee experience. Arps hyperbolic decline curve analysis was used as the main forecasting approach. In Arps analysis, ( ) ( ) 1/ 1 , b i i q t q bD t − = + where q is the flow rate, D is the decline rate, and b is the decline exponent. It will be demonstrated that forecasts using a constant b overpredicts well performance. To match the long-term performance of Elm Coulee wells, the numerical value of b had to be decreased with time. Analytical approaches (log-log type-curve diagnostic plots and the Fetkovich log-log normalized plot) were also used to decipher the flow regimes, and to determine the varying decline rate from long-term producing wells in Elm Coulee Field. In addition to analytical modeling, numerical modeling was also used because it is more comprehensive in utilizing a larger set of reservoir parameters such as reservoir heterogeneity variations. This is very useful in transferring what we learned from the long-term performance of Elm Coulee Montana wells to the short-term performance of wells in North Dakota by addressing both geology and reservoir property differences between these fields. Introduction Arps decline curve analysis has been extensively used to estimate reserves from depletion drive oil and gas reservoirs since the 1950s. The method utilizes the rate equation, ( ) ( ) 1/ 1 b i i q t q bD t − = + , where q is the flow rate, D is the decline rate given by dt q d D ln − = , and ( ) 1 / b d D dt = . It can be shown that b aq D = where b is a number between zero and one for hyperbolic decline, b equal to zero represents exponential decline and b equal to one is harmonic decline. It will be demonstrated that forecasts using a constant b , obtained from the early transient flow, overpredicts well performance for wells that have long transient flow periods. To match the long-term performance of Elm Coulee wells, the numerical value of b had to be decreased with increasing time. A theoretical reason in support of this action is given below: Yousef et al (2006) presented an analytical-numerical solution of a capacitance model to infer interwell connectivity from well rate data. Their method should work effectively for high connectivity conventional reservoirs. Nonetheless, the capacitance model can be used in low permeability, depletion-type, unconventional reservoirs, to explain why the hyperbolic decline 2 CSUG/SPE SPE 149273 exponent does not remain constant and why it decreases with time. This simple concept is consistent with field observations of production rate decline in Elm Coulee field as reported in this paper. We start with the following equations: ( ) ( ) w p p J t q − = (1) ( ) t p V c t q R t ∂ ∂ = − φ (2) where, ( ) t q is production rate, J productivity or well index, p average pressure in the drainage volume of the well, w p bottom-hole well pressure, R V drainage volume of the well, t c φ specific storage coefficient, and t time. For analytical solution to the capacitance model, J and R V are assumed constant while w p can be either constant or varying with time. When bottomhole pressure is variable, the solution involves a convolution integral. This solution can be used to explain why flowrate can increase with lowering of the bottom-hole pressure. For constant J , R V and w p , the solution of Eqs. 1 and 2 is the exponential decline of flowrate versus time (Yousef, et al, 2006). ( ) ( ) ( ) τ o t t o e t q t q − − = (3)

Pressure Transient Analyses of Short and Long Duration Well Tests in Unconventional Reservoirs

Horizontal wells are used in unconventional oil and gas reservoirs to increase production by creating large drainage surface areas and contact volumes. Production is further improved by applying hydraulic fracture stimulation in horizontal wells. Hydraulic fracturing increases well productivity via the large drainage surface of the fracture and by rejuvenating existing natural fractures as well as creating new fractures in the vicinity of the wellbore. The affected reservoir volume is known as the stimulated reservoir volume (SRV) which includes a complex flow network that creates different flow regimes. We will present several short and long pressure transient tests conducted in vertical and horizontal wells, to determine critical formation properties of the low-permeability, dual-porosity Middle Bakken and Three Forks reservoirs. Pressure transient test data were obtained via permanent downhole pressure gauges. The bilinear and linear flow regimes of the pressure buildup tests are the focus of the analyses. For this, we have presented an analytical solution using numerical inverse Laplace transform as well as closed-form approximate solutions. Flow rate transient analysis of long-duration production data were also conducted to compare with the results of the pressure transient analyses. All tests indicated that the field measured permeability is several orders of magnitude greater than permeability measured on core plugs. This indicates the presence of a network of interconnected fractures and microfractures in the stimulated near-well regions without which no significant production would result. The details of the well tests and analyses will be presented for engineering applications. Introduction In this paper we present several pressure buildup tests for horizontal and vertical wells in a North Dakota Bakken unconventional reservoir. The Bakken formation in the Williston Basin has been rapidly developing since 1980s; however, the recent advancements in horizontal well completion and stimulation technology play a key role in the success of today’s Bakken production. Pressure buildup tests, mini-DSTs and mini-frac tests are valuable sources of information for determining key reservoir properties, such as permeability. The Bakken formation is comprised of an upper and a lower organic-rich black shale and a middle silty dolostone or dolomitic siltstone, and sandstone member. The Bakken is overlain by the Lodgepole formation which consists of a dense, dark gray to brownish gray limestone and a gray calcareous shale and underlain by the Three Forks formation which is composed of thinly interbedded greenish gray and reddish brown shale, light brown to yellow gray dolostone, gray to brown siltstone, quartzite sandstone and minor occurrences of anhydrite (Kume, 1963). Historically, horizontal wells in the Bakken were drilled in the Upper Bakken formation while the recent developments have changed the focus to the Middle Bakken and Three Forks formations. Historically, when a reservoir interval has been productive it has been attributed to natural fractures (Murray, 1968). Natural fractures include regional fractures, local stress fractures and local micro-fractures resulting from pore fluid over-pressuring. Although fractures are typically determined by examining cores, image logs, and structural curvature, pressure transient tests could provide additional insight in deciphering the presence of fractures and their flow contribution.

Mini DST to Characterise Formation Deliverability in Unconventional Reservoirs

Characterization of reservoir deliverability is fundamental for the economic development of any field. In the Bakken, a need exists for reliable pressure transient tests to provide effective formation permeability of the combined fracture-matrix porous formation. This effective permeability can then be compared to laboratory measured core permeability of the matrix rock samples. This comparison is the basis for planning early production options and subsequent decisions for EOR alternatives. In the Bakken this understanding is particularly important because of the influence of massive hydraulic fracture stimulation on reservoir performance. Determining well deliverability potential by conventional drill stem tests (DST) or traditional wireline formation tests (WFT) in the past has resulted in mixed success in the Bakken. On the other hand, the mini-DST has definitely increased reliability and the success rate of pressure transient tests. The operation of mini-DST tool requires much less time than the classic DST, and multiple zone tests can be conducted to assess individual zone deliverability. The Mini-DST tool uses the conventional Wireline Formation Tester (WFT) configured with a dual-packer module and downhole pump. Tests are conducted by inflating the dual-packer module to isolate a 3-foot interval of the wellbore. Then, formation fluid is pumped out from the packer-isolated wellbore interval followed by a pressure buildup in the interval. Some simple overlay comparisons, as well as conventional pressure transient analysis, are used to interpret the drawdown and buildup pressure responses. In this paper we present several field tests which were analyzed both by conventional pressure transient analysis and numerical simulation. The analyses have provided insight into a better understanding of the flow mechanism in the Bakken both during primary production and in forecasting various improved and enhanced oil recovery proposals. The experience can also serve as a basis for test design in similar low-permeability reservoirs.

Mini-DST to Characterize Formation Deliverability in the Bakken

Characterization of reservoir deliverability is fundamental for the economic development of any field. In the Bakken, there is a need for reliable pressure transient tests to provide the effective formation permeability of the fracture-matrix in this formation for deliverability calculations. This effective permeability can then be compared to laboratory measured core permeability of the matrix rock samples. This comparison is the basis for planning early production options and subsequent enhanced oil recovery (EOR) decisions. This comparison is particularly important because of the influence of massive hydraulic fracture stimulation on reservoir performance. Determining well deliverability potential by conventional drill stem tests (DST) or traditional wireline formation tests (WFT) in the past has resulted in mixed success in the Bakken. On the other hand, the mini-DST has definitely increased reliability and the success rate of pressure transient tests. The operation of mini-DST tool requires much less time than the classic DST, and multiple zone tests can be conducted to assess individual zone deliverability. The Mini-DST tool uses the conventional Wireline Formation Tester (WFT) configured with a dual-packer module and downhole pump. Tests are conducted by inflating the dual-packer module to isolate a 3-foot interval of the wellbore. The formation fluid is pumped out from the packer-isolated wellbore interval to conduct pressure drawdown and buildup tests in the interval. An overlay of all the pressure drawdown and buildup results from various intervals is compared on a single plot to identify the most productive interval. Finally, conventional pressure transient analyses are performed to interpret all pressure drawdown and buildup tests. In this paper we present several field tests which were analyzed both by the above procedure as well as by numerical simulation. The analyses of several mini-DST results have provided insight into a better understanding of the flow mechanism in the Bakken both during primary production and in forecasting various improved and enhanced oil recovery proposals. The experience can also serve as a basis for test design in similar low-permeability reservoirs elsewhere. Introduction The Williston Basin is a large sedimentary basin that covers parts of North Dakota, Montana, South Dakota, Saskatchewan, and Manitoba (Fig. 1). The Bakken formation, regionally in the Williston Basin, is comprised of upper and lower organic-rich black shale and a middle silty dolostone or dolomitic siltstone and sandstone member (Fig. 2). The Bakken is overlain by the Lodgepole formation which consists of a dense, dark gray to brownish gray limestone and a gray calcareous shale and underlain by the Three Forks formation which is composed of thinly interbedded greenish gray and reddish brown shale, light brown to yellow gray dolostone, gray to brown siltstone, quartzite sandstone and minor occurrences of anhydrite (Kume, 1963). The Upper and Lower Bakken shale are the potential petroleum source rocks for both the Bakken and Three Forks Formations. Depositional environments for the Bakken formation range from a marine swamp with restricted circulation caused by the prolific growth of organic matter to an offshore marine environment with a stratified water column (LeFever, 1991).