Mu, Lingyu (China University of Petroleum Beijing) | Liao, Xinwei (China University of Petroleum Beijing) | Zhao, Xiaoliang (China University of Petroleum Beijing) | Zhang, Jingtian (CNPC Engineering Technology R&D Company Limited) | Zou, Jiandong (China University of Petroleum Beijing) | Chu, Hongyang (China University of Petroleum Beijing) | Shang, Xiongtao (China University of Petroleum Beijing)
Due to the special micro-pore structure and the seepage law of tight reservoirs, the research on the development of tight oil is quite different from conventional reservoirs. For the tight oil reservoirs recovered with the gas injection, the gas breakthrough is an eternal theme as a result of the preferable mobility of the gas and the strong heterogeneity of the reservoirs. It is extremely important to evaluate the sweep efficiency. Based on the stream-tube method and the non-Darcy theory, this paper establishes a rapid evaluation technique of sweep efficiency considering the mechanism of the gas flooding and the seepage characteristics of the tight oil reservoir.
Firstly, the relative permeability under different miscible condition are determined through the revised Coats model. Besides, the Todd-Longstaff model is adopted to describe the varying viscosities of oil and gas. Secondly, the stream-tube model of the inverted nine-spot well pattern with fracture is established. Next, the seepage equations of oil and gas in the stream-tube is constructed considering the threshold pressure and the variation of the viscosity and relative permeability. Then, the sweep efficiency is obtained by solving these equations. Furthermore, an application example for evaluating the sweep efficiency is presented and sensitivity analyses are conducted to study the effect of the viscosity, pressure difference, fracture permeability and well spacing taking the case of a real tight reservoir.
Through the analyses, it can be concluded that the factors have remarkable impacts on the sweep efficiency. The threshold pressure increases the resistance and reduces the flow rate, leading to a lower sweep of the injected gas. Even worse, the excessive threshold pressure results in that the effective displacement cannot be established. The fracture greatly shortened the breakthrough time and result in early channeling of the injected gas. The sweep efficiency is improved through the increase of the pressure difference and decrease of the well distance. Consequently, in order to improve the sweep efficiency of the tight reservoirs, a reasonable displacement pressure difference and a well pattern adapted to the reservoir are needed. This paper presents a rapid and effective technology to evaluate the sweep efficiency of the tight reservoirs recovered with gas injection, which provides an important basis for improving the sweep efficiency and fine development of the tight reservoir.
Dick, Michael (Green Imaging Technology) | Veselinovic, Dragan (Green Imaging Technology) | Green, Derrick (Green Imaging Technology) | Scheffer-Villarreal, Aimee (ConocoPhillips) | Bonnie, Ronald (ConocoPhillips) | Kelly, Shaina (ConocoPhillips) | Bower, Kathleen (ConocoPhillips)
Wettability is a crucial petrophysical parameter for determining accurate production rates in oil and gas reservoirs and may be especially impactful in predicting the extent of injected fluid imbibition and resultant drainage in the vicinity of hydraulic fractures within unconventional reservoirs. However, traditional industry standard wettability measurements (Amott test and USBM) often fall short when performed on unconventional samples. In this work, we adapt the existing T2-based NMR wettability index (NWI) measurement to unconventional samples in order to provide robust wettability measurements for tight rocks.
Wettability describes the affinity of a fluid to a solid surface and is dependent on rock properties such as mineralogy, aging, and brine and hydrocarbon composition. As a system always seeks to minimize surface energy toward equilibrium, whether a surface is hydrophobic (prefers to contact non-aqueous fluid molecules, usually of lesser polarity than water) or hydrophilic (prefers water) will determine the native state distribution of brine and hydrocarbon as well as the dynamic behavior of these saturations. It is well known in conventional reservoirs that wettability can greatly influence the character of relative permeability curves and production. Conventionally, water wet is the preferred state for petroleum exploration, as water will reside in the smallest pores and hydrocarbons in the larger pores and apertures, but many successful reservoirs have mixed (or intermediate) wettability. The tight pore structures of unconventional reservoirs are also sensitive to wettability controls, if not governed by them due to strong capillarity; however, the influence of wettability on matrix and matrix-fracture transport during and after hydraulic fracturing is not as well understood as in (or for?) conventional reservoirs. Learnings on the role of wettability in unconventional rocks may render useful information for the design of well completion and enhanced oil recovery strategies.
A wettability assessment such as NWI may assist with testing wettability states and controls in tight rocks in a quantitative matter. Recall that a wettability index of 1 is very water wet, −1 is very oil wet, 0 is neutral/mixed wet, and values close to 0 are weakly oil or water wet. This research demonstrates the utilization of the NWI technique on two twin sets of South Texas unconventional core plugs expected to have differing wettability due to significantly higher organic matter content in one of the sample sets. The samples, generally labeled sample 2-PX and 7-PX, are from the same well in producing acreage, but different lithological units. Sample 2-PX is a chalk and sample 7-PX is a marl; the latter has significant organic matter and clay content. Some basic petrophysical properties of these samples are listed in Table 1.
Du, Yujing (The University of Texas at Austin) | Mehmani, Ayaz (The University of Texas at Austin) | Xu, Ke (Massachusetts Institute of Technology) | Balhoff, Matthew (The University of Texas at Austin) | Torres-Verdin, Carlos (The University of Texas at Austin)
Improved understanding of the interplay between fracture and matrix fluid transport in the presence of injected water is important for the development of unconventional reservoirs. We make use of microfluidic experiments to investigate the impacts of fracture connectivity and matrix wettability on injected water sweep efficiency and viscous fingering flow patterns. Experiments are designed to mimic media with primary (hydraulic) and secondary (natural) fractures. Different oils and flow rates are used to quantify the effect of varying wettability and capillary number. We find that a secondary (natural) fracture connecting two primary (hydraulic) fractures inhibits the occurrence of viscous/capillary fingering dendrites under both water- and oil-wet conditions at low to moderate capillary numbers. At a high capillary number (10-5), however, the connected fracture promotes the generation of fingering from the inlet of the matrix, resulting in a higher recovery compared to the remaining two conditions. In contrast, a semi-connected (dead-end) secondary fracture promotes the occurrence of fingers in the porous matrix under both wetting conditions. Once dendrites penetrate the matrix, they improve sweep efficiency by displacing the resident oil. Overall, the experiments suggest that sweep efficiency is not significantly affected by the presence of a dead-end secondary fracture. Under low to medium capillary numbers, the recovery decreases with the presence of a connected secondary fracture. Under high capillary numbers, the improvement of sweep efficiency is most significant in an oil-wet system with a connected secondary fracture. Our results contribute to the design of effective enhanced oil recovery techniques by challenging the preconceived notion that fracture connectivity universally improves drainage.
Unconventional resources such as Bakken shale have made a significant impact on the global energy industry, but the primary recovery factor still lingers from 5% to 15 %. Over the past ten years, a number of pilot tests for both gas and water injection or their cyclic injection have been implemented to improve oil recovery in the Bakken Formation. The available public data show that the injectivity is not a problem, but only a small increase in production. The obvious reason is unexpected early breakthroughs even with a relatively low reservoir permeability of around 0.03 mD. Lots of experimental and simulation studies have been conducted to investigate different mechanisms behind these improved oil recoveries. However, no one has succeeded to clarify this early breakthrough.
In this study, a simulation reservoir model, including two wells, is developed, whose properties are based on public data. In terms of hydraulic fractures for each well, their geometry and conductivities are evenly built. Furthermore, our geomechanical module is applied to capture the evolution of stress field and rock failure, where a Barton-Bandis model and a Mohr–Coulomb failure criterion are applied to model tensile and shear failure, respectively. Our simulation model coupled with the geomechanical module is then implemented to explain the performance of injection pilot test.
The results of this initial study clearly show the new fractures (frac-hits) induced by water injection connect the injection and production wells, resulting in the early water breakthrough. The stress field has also been altered by the production process to favor the formation of these fractures. This study highlights the importance of geomechanics during an IOR process; identifies the reasons for the early breakthrough and provides an insight view about how to improve oil production in the Bakken Formation.
Mejia, Lucas (The University of Texas at Austin) | Mehmani, Ayaz (The University of Texas at Austin) | Balhoff, Matthew (The University of Texas at Austin) | Torres-Verdin, Carlos (The University of Texas at Austin)
We employ microfluidics to capture the impact of several diagenetic processes, including the formation of vugs and fractures, cementation, and grain dissolution, on waterflooding sweep efficiency in diagenetically altered media. Heterogeneous porous media are constructed with glass micromodels using micro-CT images of sandstones in order to mimic chemical and mechanical diagenetic processes typically encountered in subsurface rocks. Cementation was emulated by placing micrograins in intergranular pores, dissolution was introduced by replacing stress-bearing grains with arrays of micrograins, a vug was incorporated into the pore system by removing grains from a circular area in the middle of the matrix domain, and a high-permeability channel was added to study the effect of a natural fracture on flow efficiency.
From the five cases studied, we find porosity-forming processes such as those giving rise to vugs, natural fractures, and grain dissolution, result in the largest increases in recovery efficiency. Secondary pores enhance the merging of fingering dendrites, which results in higher recovery. In addition, the increase in local hydraulic conductivity due to porosity-forming diagenesis directs the fingering dendrites to traverse the middle of the matrix in addition to its boundaries. Modifying the geometry of micromodels according to probable burial stages (paragenesis), allows us to investigate the effect that subsurface conditions have on microscopic sweep and enables a quantitative interdisciplinary method for reducing reservoir development uncertainties.
Pore-scale investigations can reveal dominant underlying fluid flow mechanisms for predicting the sweep efficiency of waterflooding in porous media. In pore-scale numerical modeling, the rock pore space is discretized via meshing or represented by an approximate pore-network depending on the domain size and available computational resources. Core-flood experiments are conducted by imposing a flow rate (or pressure gradient) on the porous medium and measuring the fluid volumes at the outlet. To evaluate microscopic sweep in core floods, pore-scale images of floods performed in small cores can be acquired using fast synchrotron imaging. However, both numerical modeling and core flooding become intractable in tight rocks1 due to resolution limitations for capturing the pore space in representative domain sizes (Bultreys et al., 2016). Microfluidics experiments have the unique ability to provide controlled environments for displacement experiments, including displacement of oil by waterflooding, in short time spans (minutes to hours). In addition, microfluidics devices allow direct visualization of flow and transport at the pore scale, which provides insight for engineering more effective recovery methods for subsequent experiments.
The objective of this paper is to present a new innovative methodology that can be used to develop and evaluate the efficacy of enhanced flowback chemistries such as a novel oil-based surface modifier. This unique chemistry has been optimized to penetrate into the nanonetwork of formations, such as the Wolfcamp, with pore throat sizes as low as 110 nm at pressure differentials of only 225 psi, thereby demonstrating the ability to increase the volume of oil recovered during flowback by 250% and increasing the average producing flowrate by 194% during testing.
Although it is generally accepted that a water wet formation will lend itself to enhanced oil flowback, in unconventional formations there is a fine line between a water wet surface and the potential for increased capillary pressure, which can impact production potential. Resistance to flow in unconventional formations is created when droplets of brine form hydrogen bonded networks with the surface of the silicate formation rock creating additional capillary pressure. If the resistance is large enough it can restrict hydrocarbon flow rates out of the fractured rock formation. Nanoscale surface modification of unconventional formation rocks with the novel chemistry, SM1, can impact the wetting properties of oil and water in the nanopores and channels, disrupting the water-surface hydrogen bonding interactions, thereby decreasing the resistance to hydrocarbon flow.
The methodology used for product optimization and performance evaluation of the novel chemistries presented in this paper incorporates the use of reservoir analogues, in place of cores, in an experiment similar to core flow. The reservoir analogue replicates the inherent nanoconfined geometries of the shale reservoir rock using available geological information (e.g. pore/grain size distribution, porosity and permeability, and SEM images) and the connectivity between the induced fractures (frac zone). The reservoir oil and water samples are used to establish initial saturations. The surface wettability is also modified to capture the surface properties of the reservoir. The test methodology includes the flow of fluids in one direction into an oil saturated porous media (i.e., from frac zone into the nano network) followed by oil and water flowback in the opposite direction (i.e., from nanonetwork into the frac zone). Testing is conducted at specified reservoir representative conditions.
The nanotechnology platform offers several advantages in the product optimization and evaluation of fluid performance in unconventional rock formations. First, the specialized equipment, proprietary machine vision software, and refined testing protocols enable tests to be run efficiently in days at relevant reservoir conditions. Moreover, the platforms’ optical access enables first-of-its-kind, visual validation of performance mechanisms including surface wettability modification, emulsion characterization, and solid-precipitation if present. Additionally, this technology provides a platform that allows for repeatable results due to the high level of system control. Unlike testing with cores, analogues can be fabricated with ideal replication, eliminating the variance that cores introduce, which becomes complex, when evaluating the chemistry of fluids.
Application of polymer flooding as a chemical Enhanced Oil Recovery (EOR) has increased over recent years. The main type of polymer used is partially hydrolyzed polyacrylamide (HPAM). This polymer still has some challenges especially with shear stability and injectivity that restrict its utility, particularly for low permeability reservoirs. Injectivity limits the possible gain by acceleration in oil production due to polymer flooding. Hence, good polymer injectivity is a requirement for the success of the operation. This paper aims to investigate the influence of formation permeability on polymer flow in porous media.
In this study, a combination of core flooding with rheological studies is presented to evaluate the influence of permeability on polymer in-situ rheology behavior. The in-situ flow of HPAM polymers has also been studied for different molecular weights. The effect of polymer preconditioning prior to injection was studied through exposing polymer solutions to different extent of mechanical degradation.
Results from this study reveal that the expected shear thinning behavior of HPAM that is observed in rheometer measurements is not observed in in-situ rheology in porous media. Instead, HPAM in porous media exhibits near-Newtonian behavior at low flow rates representative of velocities deep in the reservoir, while exhibiting shear thickening behavior at high flow rates representative of velocities near wellbore region. The pressure build-up associated with shear thickening behavior during polymer injection is significantly higher than pressure differential during water injection. The extent of shear thickening is high during the injection of high Mw polymer regardless of cores' permeability. In low permeable Berea cores, shear thickening and mechanical degradation occur at lower velocities although the degree of shear thickening is lower in Berea to that observed in high permeable Bentheimer cores. This is ascribed to high polymer retention in Berea cores that results in high residual resistance factor (RRF). Results show that preshearing polymer before injection into porous media optimizes its injectability and transportability through porous media. The effect of preshearing becomes favorable for the injection of high Mw polymers into low permeability formation.
This study discusses polymer in-situ rheology and injectivity, which is a key issue in the design of polymer flood projects. The results provide beneficial information on optimizing polymer injectivity, in particular, for low permeability porous media.
Shah, Swej (Delft University of technology) | As Syukri, Herru (Delft University of technology) | Wolf, Karl-Heinz (Delft University of technology) | Pilus, Rashidah (Universiti Teknologi PETRONAS) | Rossen, William (Delft University of technology)
Foam reduces gas mobility and can help improve sweep efficiency in an enhanced oil recovery process. For the latter, long-distance foam propagation is crucial. In porous media, strong foam generation requires that local pressure gradient exceeds a critical value (∇Pmin). Normally, this only happens in the near-well region. Away from wells, these requirements may not be met, and foam propagation is uncertain.
It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability (
This article is an extension of a recent study (
Local pressure measurements and CT-based saturation maps confirm that foam is generated at the permeability transition, which then propagates downstream to the outlet of the core. A significant reduction in gas mobility is observed, even at low superficial velocities, however, the limit of foam propagation is reached at the lowest velocity tested. CT images were used to quantify the accumulation of liquid near the permeability jump, causing local capillary pressure to fall below the critical capillary pressure required for snap-off. This leads to foam generation by snap-off. At the tested fractional flows, no clear trend was observed between foam strength and fg. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous work (Rossen, 1999). Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate - probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and increasing fractional flow. Within the range of conditions tested, the onset of foam generation (identified by the rise in ∇P and Sg) occurs after roughly the same amount of surfactant injection, independent of fractional flow or injected rate.
Guetni, Imane (IFP Energies nouvelles – Rueil-Malmaison Université de Lorraine, CNRS, LIEC - Nancy) | Marliere, Claire (IFP Energies nouvelles – Rueil-Malmaison) | Rousseau, David (IFP Energies nouvelles – Rueil-Malmaison) | Bihannic, Isabelle (Université de Lorraine, CNRS, LIEC - Nancy) | Pelletier, Manuel (Université de Lorraine, CNRS, LIEC - Nancy) | Villieras, Frédéric (Université de Lorraine, CNRS, LIEC - Nancy)
Chemical EOR is now considered as an attractive option for sandstone reservoirs with permeability below 100mD, in particular where lack of gas supply does not allow gas injection (
Beyond a few reference textbooks (
In the case of porous media with low permeability for chemical EOR (below 100mD), typically characterized by small pores throats and complex mineralogical composition, thoses issues are all the more important. Low permeability sandstones are usually rich in clay, responsible for high polymer retention (
The Alvheim field, offshore Norway, has subsea wells with long horizontal branches completed with sand screens. After 10 years of production, water production starts to constrain the oil production. Mechanical water shut-off is impossible in these wells, hence other methods are of interest. In a well workover in 2013, two high-viscous polymer pills were bull-headed and squeezed into the reservoir. The well productivity was reduced with around 50% while the water-cut dropped and pointed to potentially 3 mmstb of extra oil recovery. A research study was initiated with the objectives to understand the changed well performance and if polymer bull-heading can be a future method to reduce water production and enhance oil production.
An experimental laboratory program started with filtration tests of polymer solutions based on the polymer used in the well operation. Core flood experiments were performed by injecting polymer into two parallel mounted cores, then back producing these individually with either water or oil. Several combinations of parallel cores were tested with polymer injection: high vs. low permeability, high oil saturation vs. low oil saturation, outcrop sandstone vs. Alvheim core, as well as two different polymer versions.
The polymer recipe as used in the well operation showed to plug standard filters with filter size larger than the reservoir pore sizes but did not plug the cores. The polymer recipe as used in the well gave a better disproportionate permeability reduction (DPR) than the alternative polymer variant with similar viscosity. A theoretical model for the shear rate in the porous media matched the experimental measured data excellent. The core results show a stable permeability reduction factor of 100-450 for water, while only a factor 2-10 and decreasing with time for oil. The achieved DPR ratio of 45-80 is better than the trend from earlier published results.
The DPR as measured in the laboratory was next integrated in the reservoir model as part of the history match of the treated well. The Alvheim field has several reservoir zones separated with thin shales, and this reservoir zonation seems key for this EOR method to work.
The laboratory work, the reservoir studies and the field experience all point to a possible robust and simple EOR method for Alvheim and similar oil fields. The polymer seems to act as a "magic filter", allowing oil to pass while not water. Future work includes more research and maturing a new polymer pilot on Alvheim.