Production from shales can be dependent on many things, including multiple reservoir properties, drilling, completion and production methods. Designs and analyses often focus on drilling and completion issues, such as number of stages, wellbore length and fracture properties, such as conductivity, length, spacing and complexity. As a result, many aspects of the reservoir, fractures and production methods can be significant. Flow from the reservoir to production points is driven by pressure drops. If an entire well including fractures and surrounding reservoir is considered as a single system, then the production behavior is driven by the magnitude of three pressure drops and corresponding resistances to flow in the system. Those that need to be considered are: pressure drop between the reservoir and the fractures, pressure drop along the fractures to the wellbore perforations and pressure drop along the wellbore to the pump inlet or tubing head. Different aspects of the well/fracture/reservoir system become important, or unimportant, depending on the relative magnitude of these pressure drops and resistances to flow. For example, many people believe that fractures should be as long as possible assuming they can be restricted to zones of interest and do not interfere with other wells and/or fractures. However, since the pressure along a fracture increases as you move further away from the wellbore, increasing fracture length can have diminishing returns for reservoirs with small reservoir to fracture pressure drops and/or low fracture conductivities.
Se, Yegor (Chevron Energy Technology Company) | Villegas, Mauricio (Chevron) | Iskakov, Elrad (Chevron) | Playton, Ted (Tengizchevroil) | Lindsell, Karl (Tengizchevroil) | Cordova, Ernesto (Chevron Energy Technology Company) | Turmanbekova, Aizhan | Wang, Haijing
Secondary oil recovery projects in naturally fractured carbonate reservoirs (NFR) often introduce uncertainties and challenges that are not common to conventional waterfloods. The recovery mechanism in NFRs relies on ability of the fracture network to deliver enough injected fluid to the matrix, as well as rate and magnitude of capillary interactions within the matrix rock, during which hydrocarbon displacement occurs. The imbibition measurements can be performed in the laboratory using core samples, but due to reservoir heterogeneity, certain limitations of the lab equipment and the quality of the core material, scalability of the core results to a reservoir model can be challenging.
This paper describes the design, execution and evaluation of the’ log-soak-log’ (LSL) pilot test conducted in a giant naturally fractured carbonate reservoir with a low-permeability matrix in Western Kazakhstan, where repeatable and reliable measurements of changes in water saturation were achieved across large intervals (tens of meters) using a time-lapse pulsed-neutron logging technique. Periodic measurements provided valuable observations of dynamic change in saturation and fluid level over time and allowed estimation of the rate and magnitude of imbibition in the slope margins, depositional settings and rock types of interest. Incorporation of the LSL results into reservoir models validated the ranges of water-oil relative permeability curves, residual oil saturation to water, irreducible water saturation, and capillary pressure assumptions. This validation constrained key subsurface uncertainty and updated the oil recovery forecast in several improved oil recovery (IOR) waterflood projects.
Abdelfatah, Elsayed (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Wahid-Pedro, Farihah (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Melnic, Alexander (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Vandenberg, Celine (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Luscombe, Aidan (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Berton, Paula (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Bryant, Steven (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada)
Waterflooding of heavy oil reservoirs is commonly used to enhance their productivity. However, preferential pathways are quickly developed in the reservoir due to the significant difference in viscosity between water and heavy oil, and hence, the oil is trapped. Here, we propose a platform for designing ultra-low IFT solutions for reducing the capillary pressure and mobilizing the heavy oil.
In this study, mixtures of organic acids and bases were formulated. Three different formulations were tested: (i) Ionic liquid (IL) formulation where bulk acid (4-dodecylbenzene sulfonic acid) and base (Tetra-
The IL and ABs formulation are acidic solutions with pH around 3. The ASBs formulation is highly basic with a pH around 12. Non of the formulations salted out below 14 wt% of NaCl. While conventional surfactant, SDBS, precipitated at salt concnetration less than 2 wt% of NaCl. The formulation solutions (1 wt%) have different optimum salinities: 2.5 wt% NaCl for ASBs, 3 wt% NaCl for IL and AB. Although IL and AB have the same composition and molar ratio of the components, their performances are completely different, indicating different intermolecular interactions in both formulations. Corefloods were conducted using sandpack saturated with Luseland heavy oil (~15000 cP) and at fixed Darcy velocity of 12 ft/day. A slug of 1 PV of each formulation was injected after waterflooding for 5 PV and followed by 5 PV post-waterflooding. In the hydrophilic sandpacks, IL and AB formulation produced an oil bank, consisting mainly of W/O emulsion, with oil recovery that is 1.7 times what was recovered by 11 PV of waterflooding solely. Majority of the oil was recovered in the 2 PV of waterflood following the IL slug. ASBs formulations produced O/W emulsions with prolonged recovery over 5 PV waterflooding after the ASB slug. The recovery factor for ASBs was 1.6 times that recovered for 11 PV of waterflooding only. In the hydrophobic sandpacks, The ASB formulation slightly increased the recovery factor compared to only waterflooding. While for IL and AB formulation, the recovery factor decreased.
This work presented a novel platform for tuning the recovery factor and the timescale of recovery of heavy oil with a variable emulsion type from O/W to W/O depending on the intermolecular interactions in the system. The results demonstrate that the designed low IFT solutions can effectively reduce the capillary force and are attractive for field application.
Cronin, Michael (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University) | Emami-Meybodi, Hamid (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University) | Johns, Russell (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University)
We present a new semi-analytical compositional simulator specifically designed for hydrocarbon recovery (primary and cyclic solvent injection processes) in ultratight oil reservoirs based on diffusion-dominated transport within the matrix. The semi-analytical solution consists of a well-mixed tank model for the fractures coupled to diffusive transport within the matrix. Production of oil, gas, and water from the fractures is proportional to its phase saturation. The matrix allows for differing effective diffusion coefficients for each component. Because there are no grid blocks within the matrix the analytical solution is computationally less expensive than numerical simulation while capturing the steep, non-monotonic compositional changes occurring a short distance into the matrix owing to multiple injection cycles. The Peng-Robinson equation-of-state is used to calculate phase behavior within the analytical framework.
The solution is validated with several lab and field-scale cases. For primary recovery, the results show that the diffusion-based simulator correctly reproduces the pressure and oil recovery declines observed in the field. We show that the hydrocarbon recovery mechanism for solvent huff‘n’puff (HnP) is facilitated by greater density reduction and compositional changes (increased compositional gradients). Two solvents are considered in HnP calculations; carbon dioxide (CO2) and methane (CH4). Recovery of heavier components is enhanced with CO2 compared to CH4, but methane has overall greater oil recovery than carbon dioxide for the cases considered. Furthermore, the results demonstrate that multiple huff‘n’puff cycles constrained to surface injection are needed to enhance density and compositional gradients, and therefore oil recovery. While shorter soaks are better for short-term recovery (i.e. 3 to 5 years), longer soak periods maximize recovery over a longer timeframe (i.e. 10 to 15 years). This paper provides a novel way to model the optimum number of cycles and duration and when to start the HnP process after primary recovery for the limiting case of diffusion only transport where matrix permeabilities are very small (k < 200 nd).
He, Youwei (China University of Petroleum, Beijing) | Cheng, Shiqing (China University of Petroleum, Beijing) | Chai, Zhi (Texas A&M University) | Patil, Shirish (King Fahd University of Petroleum and Minerals) | Rui, Ray (Massachusetts Institute of Technology) | Yu, Haiyang (China University of Petroleum, Beijing)
Applications of cluster wells and hydraulic fracturing enable commercial productivity from unconventional reservoirs. However, well productivity decrease rapidly for this type of reservoirs, and in many cases, it is difficult to maintain a productivity that is economical. Enhanced oil recovery (EOR) is therefore needed to improve well performance. Traditional fluid injection from other wells are not feasible due to the ultra-low permeability, and fluid Huff-n-Puff also fails to meet the expected recovery. This work investigates the feasibility of the inter-fracture injection and production (IFIP) approach to increase oil production of multiple multi-fractured horizontal wells (MFHW).
Three MFHWs are considered in a cluster well. Each MFHW includes injection fractures (IFs) and recovery fractures (RFs). The fractures with even and odd indexes are assigned to be IFs or RFs, respectively. The injection/production schedule falls into two categories: synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). To analyze the well performance of multiple MFHWs using the IFIP method, this work performs numerical simulation based on the compartmental embedded discrete fracture model (cEDFM) and compares the production performance of three MFHWs using four different producing methods (i.e., primary depletion, CO2 Huff-n-Puff, s-IFIP, and a-IFIP). Although the number of producing fractures is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than primary depletion and CO2 Huff-n-Puff. Sensitivity analysis is performed to investigate the impact of parameters on the IFIP. The fracture spacing between IFs and RFs, CO2 injection rates, and connectivity of fracture networks affect the oil production significantly, followed by length of RFs, well spacing among MFHWs and length of IFs. The suggested well completion scheme is presented for the a-IFIP and s-IFIP methods. This work demonstrates the ability of the IFIP method in enhancing oil production of multiple MFHWs in unconventional reservoirs.
In preparation for a field pilot of cyclic solvent injection (CSI) on two depleted cold heavy oil production with sand (CHOPS) wells, a series of oilsands coreflood experiments were conducted to evaluate the effectiveness of various commercially available solvents and make a solvent recommendation for the pilot. Oil recovery and solvent recovery were the key performance indicators used to compare CSI effectiveness of each solvent blend. The operating pressure for each test was kept relatively constant for each solvent blend tested. Tested solvents included blends of methane/propane, carbon dioxide/propane, methane/ethane, 100% ethane, and nitrogen. Sensitivities for depletion rate and blowdown pressure are also presented. Overall the 100% ethane test performed the best with the highest oil recovery and solvent recovery in the fewest cycles. Due to the lack of commercial ethane supply and the industry experience with methane/propane in Husky Edam’s CSI pilot, a methane/propane blend was recommended for the field pilot in Manatokan East near Bonnyville Alberta Canada.
Hansen, Mary (McDaniel & Associates Consultants) | Hamm, Brian (McDaniel & Associates Consultants) | Wynveen, Jared (McDaniel & Associates Consultants) | Schlosser, Tyler (McDaniel & Associates Consultants) | Jenkinson, David (McDaniel & Associates Consultants) | Dang, Hoang (McDaniel & Associates Consultants)
Unconventional reservoirs with low permeability shales and siltstones are currently being developed using horizontal wells in multiple layers. As this development technique has become more common, accurately understanding well-to-well communication is increasingly critical. Well positioning, reservoir thickness and well interference effects are important factors in the success of multi-layer development. Traditional well density metrics such as wells per section and lateral well spacing do not account for the multi-layer nature of these plays. This paper introduces readily derived metrics that enable a three-dimensional (3D) quantification of multi-layer well density.
Unlike traditional analysis which considers pad development from a bird’s eye view, this paper considers the vertical cross-section of a pad which enables the 3D drainage to be quantified. The metrics Cross-Sectional Drainage Area (XDA) and Three-Dimensional Proppant Intensity (3DPI) are defined. XDA quantifies the well density relative to the thickness of the reservoir. 3DPI represents completion intensity and reservoir stimulation relative to the cubic volume of gross rock attributed to the multi-layer development. Once introduced, these two metrics are correlated to well and pad level performance. Examples from the Montney Formation in Western Canada and the Bakken Formation in North Dakota, USA are studied in detail.
Ultimate hydrocarbon recovery factors, early time well performance and production profiles are analyzed and compared to the XDA and 3DPI metrics using visual analytics and multivariate machine learning models. In both the Montney and Bakken examples, XDA correlates with well performance and 3DPI correlates with pad hydrocarbon recovery factors.
Lou, Xuanqing (Pennsylvania State University) | Chakraborty, Nirjhor (Pennsylvania State University) | Karpyn, Zuleima (Pennsylvania State University) | Ayala, Luis (Pennsylvania State University) | Nagarajan, Narayana (Hess Corp.) | Wijaya, Zein (Hess Corp.)
The design of oil recovery processes by gas injection or vapor solvent relies on knowledge of diffusion coefficients to enable meaningful production predictions. However, lab measurements of diffusion coefficients are often performed on bulk fluids, without accountability for the hindrance caused by the pore network structure and tortuosity of porous media. As such, our ability to predict effective diffusion coefficients in porous rocks is inadequate and, additional laboratory work is needed to investigate the impact of the medium itself on transport by diffusion. In addition, experimental data on multi-phase diffusion coefficients are particularly scarce for tight rocks. This study therefore proposes an experimental methodology, based on a pressure-decay technique, to measure diffusion of injected gas in oil saturated porous rocks. A diffusion experiment of gas into bulk oil (without porous medium) provides an upper limit estimation of this gas-liquid diffusion coefficient. Diffusion experiments using limestone and Bakken shale provide insight into different degrees of restriction in high permeability versus low permeability media. Two analytical models and one numerical model were implemented and compared to determine the diffusion coefficients from the time-dependent experimental pressure-decay data. These diffusion coefficients were found in agreement with literature on corresponding data, demonstrating the validity of the modeling approaches used. Results indicate considerable hindrance to diffusion in porous media relative to bulk oil and relates to the tortuosity and constrictivity of the rock matrix. The diffusion coefficient of methane in bulk oil is 3.8 × 10−9 m2/s. In our limestone sample, this diffusion coefficient drops by one order of magnitude, ranging between 1.5 to 6.5 × 10−10 m2/s and, it drops by another order of magnitude in the Bakken shale sample to 2.0 × 10−11 m2/s.
While many factors in the reservoir cannot be controlled, there are three controllable factors in field development that make a significant impact. More reservoir contact leads to more oil produced. Controlling sand and water means lower treatment costs, and in-situ reservoir management leads to higher cumulative production. While the underlying technologies have been around for up to 20 years, it is only recently that their synergies and true value are understood. This paper will demonstrate the effect each of these technologies has on increasing overall production rates, improving recovery, and reducing the cost per Barrel of Oil Equivalent (BOE).
The successful implementation of multilaterals in the North Sea will be analyzed. Since 1996, over 300 multilateral junctions have been installed on the Norwegian continental shelf fields with currently approximately 30 junctions completed each year.
Additionally, simulations will be used to demonstrate the incremental improvements in oil recovery that can be obtained by using properly designed advanced completions that include multilaterals, sensors, and passive/active flow control equipment.
The paper will evaluate production performance of a vertical well field development base case against scenarios using horizontal and multilateral wells. It will show how fields can be optimized, leading to increased oil and decreased water production.
Production rates can be significantly improved by combining multilaterals with other advanced completion techniques, such as intelligent completions and inflow control devices. The subject field simulation can be further optimized to manage gas and water production.
With a tailored multilateral field design, combined with properly designed advanced completions systems, the simulation succeeds in terms of achieving maximum contact with the oil reservoir and meeting improved ultimate recovery objectives.
It can be concluded that as reservoir contact is increased, a reduced decline in production rate is observed leading to both a higher Estimated Ultimate Recovery (EUR) and optimized drawdown profile distributions. Additionally, results will be presented that have considered oil production and a method to lower production of unwanted fluids or gas.
This paper also demonstrates the value of field development design from the perspective of reservoir simulation. It is through reservoir insight that a level of understanding is created that can help define the optimum well and completion design to meet field expectations.
Advanced multilaterals continue to grow in popularity with many operators, and it therefore becomes important to evaluate the value of different field development methods. This knowledge can aid operators in unlocking new reservoir targets and optimizing field development, and ultimately will improve recovery factors and overall field economics.
Non-thermal-solvent and thermal-solvent based heavy oil recovery processes are technologies in which solvent is used as either the main or the secondary agent, in conjunction with heating, for bitumen viscosity reduction. In these processes a hydrocarbon solvent is injected into the reservoir and produced back with the recovered bitumen. A fraction of the injected solvent is retained in the reservoir at an equilibrium state as gas and liquid phases. Since the cost of injected solvent in these processes is a major portion of the operating cost, recovery of the retained solvent from the reservoir at the end of bitumen depletion stage results in recovery of significant capital and thus improvement of the process economics.
Imperial-ExxonMobil have been optimizing the existing and developing new recovery technologies to improve the efficiencies, economics and environmental performance of heavy oil production operations. Recent focus has been on developing solvent based recovery processes through an integrated research program that includes fundamental laboratory work, advanced numerical simulation studies, laboratory scaled physical modeling, and field piloting. The research program aims at in-depth investigation and understanding of process physics and mechanisms to allow evaluating and optimizing process performance.
In this paper, development of a new method for recovery of the retained solvent from the reservoir at the end of the bitumen depletion stage is introduced. This method takes advantages of solvent vapor-liquid thermodynamic equilibrium to strip the retained solvent from the reservoir. A stripping gas is injected and circulated in the bitumen depleted chamber to vaporize and recover the retained solvent to the surface. The reservoir modeling results show that this method is very effective and efficient in accelerating recovery of the retained solvent. The physical modeling experimental data confirms the effectiveness of this method. Field pilot data from a solvent assisted recovery process are presented which demonstrate solvent recovery efficiency using continuous steam injection.