Guedez, Andreina (MetaRock Laboratories) | Mickelson, William (MetaRock Laboratories) | Aldin, Samuel (MetaRock Laboratories) | Gokaraju, Deepak (MetaRock Laboratories) | Mitra, Abhijit (MetaRock Laboratories) | Thombare, Akshay (MetaRock Laboratories) | Patterson, Robert (MetaRock Laboratories) | Aldin, Munir (MetaRock Laboratories)
Laboratory measurements of porosity and matrix permeability are essential for accurate petrophysical characterization to aid in optimized planning for field development. The core must be cleaned before any petrophysical properties, such as porosity and permeability, are measured. The goal of the cleaning process is to remove all hydrocarbons, water and any possible invasion of drilling fluid during the coring process. Multiple cleaning methods, including flow-through cleaning, centrifuge flushing and distillation/extraction using Dean-Stark or Soxhlet methods are used and have been proven to be effective methods in conventional core. However, for unconventional rocks with ultra-low permeability like shales, the above methods are ineffective and time consuming. The distillation/extraction cleaning process has potential to induce micro fractures and/or parting of the rock that affect the measurements. Moreover, some cleaning methods for tight rocks involve crushing the sample to make the process time efficient. The disadvantages with this method include destroying the pore structure and rock fabric, overestimation of permeability and the amount of removable fluids and the inability to measure permeability under stress.
In this paper, an alternative technique for removal of mobile fluids from intact plug samples for subsequent permeability measurement is explored. The method involves multiple cycles of pressurized CO2 driven extraction. Samples from low permeability formations were cleaned using the proposed method. CT scans, microscopic images and steady state permeability measurements were employed to ensure the samples selected for this study were free of any pre-existing fractures. The weights of the samples were monitored at the end of each cleaning cycle. The cleaning process was considered complete when the weights stabilized. Comparison of pre and post cleaning oil and water saturation measurements using Karl-Fischer, Pyrolysis, and NMR indicate a significant decrease in fluid saturations. Lastly, porosity of the samples also increased as a result of the cleaning process.
The technique introduced in this paper provides a means to more accurately measure the absolute matrix permeability of ultra-tight rock, improving the understanding of fundamental petrophysical properties.
Martini, Brigette (Corescan Inc.) | Bellian, Jerome (Whiting Petroleum Corporation) | Katz, David (Encana Corporation) | Fonteneau, Lionel (Corescan Pty Ltd) | Carey, Ronell (Corescan Pty Ltd) | Guisinger, Mary (Whiting Petroleum Corporation) | Nordeng, Stephan H. (University of North Dakota)
Hyperspectral core imaging studies of the Bakken-Three Forks formations over the past four years has revealed non-destructive, high resolution, spatially relevant insight into mineralogy, both primary and diagenetically altered that can be applied to reservoir characterization. While ‘big’ data like co-acquired hyperspectral imagery, digital photography and laser profiles can be challenging to analyze, synthesize, scale, visualize and store, their value in providing mineralogical information, structural variables and visual context at scales that lie between (and ultimately link) nano and reservoir-scale measurements of the Bakken-Three Forks system, is unique.
Simultaneous, co-acquired hyperspectral core imaging data (at 500 μm spatial resolution), digital color photography (at 50 μm spatial resolution) and laser profiles (at 20 μm spatial and 7 μm vertical resolution), were acquired over 24 wells for a total of 2,870 ft. of core, seven wells of which targeted the Bakken-Three Forks formations. These Bakken-Three Forks data (~5.5 TB) represent roughly 175,000,000 pixels of spatially referenced mineralogical data. Measurements were performed at a mobile Corescan HCI-3 laboratory based in Denver, CO, while spectral and spatial analysis of the data was completed using proprietary in-house spectral software, offsite in Perth, WA, Australia. Synthesis of the spectral-based mineral maps and laser-based structural data, with ancillary data (including Qemscan, XRD and various downhole geophysical surveys) were completed in several software and modelling platforms.
The resulting spatial context of this hyperspectral imaging-based mineralogy and assemblages are particularly compelling, both in small scale micro-distribution as well as borehole scale mineralogical distributions related to both primary lithology and secondary alteration. These studies also present some of the first successful measurement and derivation of lithology from hyperspectral data. Relationships between hyperspectral-derived mineralogy and oil concentrations are presented as are separately derived structural variables. The relationship between hyperspectral-based mineralogy to micro-scale reservoir characteristics (including those derived from Qemscan) were studied, as were relationships to larger-scale downhole geophysical data (resulting in compelling correlations between variables of resistivity and hyperspectral-mineralogy). Finally, basic Net-to-Gross calculations were completed using the hyperspectral imaging data, thereby extending the use of such data from geological characterizations through to resource estimations.
The high-fidelity mineralogical maps afforded by hyperspectral core imaging have not only provided new geological insight into the Bakken-Three Forks formations, but ultimately provide improved well completion designs in those formations, as well as a framework for applying the technology to other important unconventional reservoir formations in exploration and development. The semi-automated nature of the technology also ushers in the ability to consistently and accurately log mineralogy from multiple wells and fields globally, allowing for advanced comparative analysis.
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.
Yang, Yuhao (University of Kansas) | Fu, Qinwen (University of Kansas) | Li, Xiaoli (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Barati, Reza (University of Kansas) | Negahban, Shahin (University of Kansas)
The visualization and quantification of CO2 and oil interactions give insight into the multiple mechanisms controlling CO2 enhanced oil recovery processes. In this work, a high pressure high temperature full visual Pressure-Volume-Temperature (PVT) system is used to measure the equilibrium parameters including oil volume, gas volume and equilibrium pressure. In consequence, equilibrium properties including CO2 solubility, oil swelling factor and extraction pressure can be calculated and observed. In non-equilibrium condition, CO2 condensation and light oil component extractions are observed, as well as pressure decay data due CO2 dissolution is recoded. Furthermore, diffusion coefficient is calculated based on pressure data. Hence, the mechanisms of CO2 EOR process are identified and analyzed.
Firstly, excessive gaseous CO2 is charged into the piston-equipped view cell coexisting with the pre-loaded Bakken oil. Three types of phase behavior can be captured under certain conditions including liquid oil-Vapor CO2 (LV), liquid oil-liquid CO2-Vapor CO2 (L1L2V), and liquid oil-liquid CO2 (L1L2), which are common fluid types in the formation during CO2 EOR process. In equilibrium process, the cell is pressurized stepwise. The volume of the swollen oil caused by the dissolution of CO2 is recorded at each equilibrium pressure step, at which gas solubility, swelling factor as well as extraction pressure can be calculated and determined. Once the light components in Bakken oil start to be extracted into the liquid CO2 phase, the volume of oil-rich phase decreases and a couple of extraction columns can be observed. The heavy components in oil are harder to be extracted so that the oil volume eventually reaches a plateau. During the non-equilibrium process, the pressure increases continuously by moving the piston at the various rates until the pressure reaches the desired pressure at different temperatures. Finally, the pressure decay method is used to determine the diffusion coefficient between CO2 and Bakken oil.
It has been found that oil can be swollen by dissolving CO2 at high pressures. The swelling factor increases with pressure during LV condition, where the EOR mechanism is mainly oil swelling effect. However, the swelling factor decreases with pressure during L1L2V and L1L2 conditions, indicating a change in the main controlling mechanism to CO2. As for the non-equilibrium process, the extraction is found to be closely related to the CO2 physical state. The condensing flow from CO2 rich liquid phase to oil phase and the extracting flow from oil phase to CO2 rich liquid phase have been filmed to demonstrate the EOR mechanisms. The effective diffusion coefficient in Period I, which is dominated by natural convection, is found to be three orders larger than that in Period II, which is mainly driven by molecular diffusion.
In this work, both equilibrium and non-equilibrium properties have been measured and observed by using a piston-equipped visual cell. The mechanisms of CO2 EOR for Bakken oil have been comprehensively identified and analyzed at the different stages for the first time. This work sheds new light on the design of CO2-EOR application in unconventional oil reservoirs.
Geri, Mohammed Ba (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Ofori, Bruce (Missouri University of Science and Technology) | Flori, Ralph (Missouri University of Science and Technology) | Sherif, Huosameddin (Missouri University of Science and Technology)
Recent studies have presented successful case studies of using HVFR fluids in the field. Reported cost reductions from using fewer chemicals and less equipment on the relatively small Marcellus pads when replacing linear gel fluid systems by HVFR. The investigation provided a screening guideline of utilizing HVFRs in terms of its viscosity and concentration. The study notes that in field application the average concentration of HVFRs is 2.75 gpt (gal per 1,000 gal)
Three different scenarios were selected to study fluid type effect using 3D pseudo simulator; as a first scenario; fracture dimensions as a second scenario; the last scenario was proppant type. The first scenario consists of two cases: utilizing HVFR-B as new fracture fluid in 20% of produced water was investigated in scenario I (base case). Comparison between HVFR and linear gel in the Middle Bakken was investigated in Case II of the first scenario. At the second scenario, fracture half-length was studied. Proppant distribution impact by using HVFR in Bakken formation was analyzed as the third scenario. The final scenario investigated the pumping flow rate influence on proppant transport of using HVFR. The concentration of HVFR-B was 3 gpt and the proppant size was 30/50 mesh. The treatment schedule of this project consists of six stages. The proppant concentration was increased gradually from 0.5 ppt to 6 ppt at the later stage.
In the case of using HVFR-B the fracture half-length was approximately 1300 ft while using linear gel created smaller fracture half-length. In contrast, using linear gel makes the fracture growth increase rapidly up to 290 ft as showed. To conclude, using HVFR-B created high fracture length with less fracture height than linear gel. Additionally, in using HVFR-B, the average fracture height was approximately 205 ft while using linear gel created increasing of the fracture growth rapidly up to 360 ft which represent around 43% increasing of the fracture height. In studying the impact of fracture half-length on proppant transport, increasing fracture half-length from 250 ft to 750 ft leads to the fracture growth rapidly up to 205 ft
Studying the impact of proppant size effect on proppant transport, we observed changing fracture conductivity across fracture half-length. Thus, the fracture height increasing with decreasing proppant mesh size. Fracture height increased from 193 ft to 206 ft by changing proppant mesh size from 20/40 to 40/70 mesh. With flow rate impact on proppant transport, it was observed that, the fracture height increases by increasing the pump rate. Utilizing HVFR-B in the fracture treatment provides higher absolute open flow rate (AOF) which is around 2000 BPD. On the other hand, the outcomes of using linear gel has less AOF that about 1600 BPD. Also, Increasing the Xf and proppant mesh size leads to increase the AOF.
This project describes comparison of the successful implementation of utilizing HVFR as an alternative fracturing system to linear gel.
The results of an investigative research study on the impact of the in-situ stress, shale matrix composition, maturity, amount of organic matter and clay composition affecting the anisotropy level of the geomechanical properties have been discussed in this paper. These parameters are among the key factors known to control the geomechanical properties in organic-rich shale formations. Organic-rich shale formations with different mineralogical compositions and organic matter maturity have been measured under uniaxial and triaxial stress state along with the field data from limited number of the wells in these shale basins where the core samples are obtained to investigate the role of each factor on the level of geomechanical anisotropy.
The field data has been analyzed to compare the trends obtained from the laboratory data collected under customized controlled field conditions to the field data trends. Artificial Neural Network (ANN) analysis was used in wells without full log suits to obtain the anisotropic geomechanical parameters. The results highlight the maturation, organic richness and clay composition effect on the recorded field data as well as the geomechanical properties obtained from the laboratory measurements.
The stress and fluid sensitivity of shale formations have been well recognized since the early days of conventional reservoir drilling, completion and production operations as they typically require special attention for minimizing wellbore instability during drilling and maintaining high integrity wells throughout the life cycle of these wells. Shales are highly heterogeneous and anisotropic formations and their source rock characteristics also have introduced further complexities with the organic matter and compositional variations throughout the areal extent of the reservoirs. These variations and their alterations as a function of the level of maturity of the organic matter require further study for better understanding of the differences and similarities between the seal shales and reservoir shales and the role of the organic matter and its maturity level in these differences. One of the critical aspects of the organic matter presence is in quantification of shale mechanical properties and strength and their direction dependence for successful field development. The level of maturity of the organic matter also influences the mechanical, acoustic, petrophysical and failure properties of organic rich shale formations. The mineralogical composition typically deviates from carbonate rich to quartz rich in the rock matrix with clay and organic matter amount and distribution heterogeneity in the reservoir. The layered structure introduced by the depositional history of the formation along with the heterogeneity in the distribution of organic matter result in various degree of anisotropy in reservoir properties (Sondergeld and Rai, 2011; Vernik and Milovac, 2011). A better understanding on the anisotropic characteristics of the shale formations and key parameters impacting the anisotropy is essential for field operational success from exploration studies for seismic attributes to reservoir characterization, drilling and hydraulic fracture design and production optimization.
Recent studies have indicated that Huff-n-Puff (HNP) gas injection has the potential to recover an additional 30-70% oil from multi-fractured horizontal wells in shale reservoirs. Nonetheless, this technique is very sensitive to production constraints and is impacted by uncertainty related to measurement quality (particularly frequency and resolution), and lack of constraining data. In this paper, a Bayesian workflow is provided to optimize the HNP process under uncertainty using a Duvernay shale well as an example.
Compositional simulations are conducted which incorporate a tuned PVT model and a set of measured cyclic injection/compaction pressure-sensitive permeability data. Markov chain Monte Carlo (McMC) is used to estimate the posterior distributions of the model uncertain variables by matching the primary production data. The McMC process is accelerated by employing an accurate proxy model (kriging) which is updated using a highly adaptive sampling algorithm. Gaussian Processes are then used to optimize the HNP control variables by maximizing the lower confidence interval (μ-σ) of cumulative oil production (after 10 years) across a fixed ensemble of uncertain variables sampled from posterior distributions.
The uncertain variable space includes several parameters representing reservoir and fracture properties. The posterior distributions for some parameters, such as primary fracture permeability and effective half-length, are narrower, while wider distributions are obtained for other parameters. The results indicate that the impact of uncertain variables on HNP performance is nonlinear. Some uncertain variables (such as molecular diffusion) that do not show strong sensitivity during the primary production strongly impact gas injection HNP performance. The results of optimization under uncertainty confirm that the lower confidence interval of cumulative oil production can be maximized by an injection time of around 1.5 months, a production time of around 2.5 months, and very short soaking times. In addition, a maximum injection rate and a flowing bottomhole pressure around the bubble point are required to ensure maximum incremental recovery. Analysis of the objective function surface highlights some other sets of production constraints with competitive results. Finally, the optimal set of production constraints, in combination with an ensemble of uncertain variables, results in a median HNP cumulative oil production that is 30% greater than that for primary production.
The application of a Bayesian framework for optimizing the HNP performance in a real shale reservoir is introduced for the first time. This work provides practical guidelines for the efficient application of advanced machine learning techniques for optimization under uncertainty, resulting in better decision making.
Liu, Guoxiang (Baker Hughes a GE Company) | Stephenson, Hayley (Baker Hughes a GE Company) | Shahkarami, Alireza (Baker Hughes a GE Company) | Murrell, Glen (Baker Hughes a GE Company) | Klenner, Robert (Energy & Environmental Research Center, University of North Dakota) | Iyer, Naresh (GE Global Research) | Barr, Brian (GE Global Research) | Virani, Nurali (GE Global Research)
Optimization problems, such as optimal well-spacing or completion design, can be resolved rapidly via surrogate proxy models, and these models can be built using either data-based or physics-based methods. Each approach has its strengths and weaknesses with respect to management of uncertainty, data quality or validation. This paper explores how data- and physics-based proxy models can be used together to create a workflow that combines the strengths of each approach and delivers an improved representation of the overall system. This paper presents use cases that display reduced simulation computational costs and/or reduced uncertainty in the outcomes of the models. A Bayesian calibration technique is used to improve predictability by combining numerical simulations with data regressions. Discrepancies between observations and surrogate outcomes are then observed to calibrate the model and improve the prediction quality and further reduce uncertainty. Furthermore, Gaussian Process Regression is used to locate global minima/maxima, with a minimal number of samples. To demonstrate the methodology, a reservoir model involving two wells in a drill space unit (DSU) in the Bakken Formation was constructed using publicly available data. This reservoir model was tuned by history matching the production data for the two wells. A data-based regression model was constructed based on machine learning technologies using the same dataset. Both models were coupled in a system to build a hybrid model to test the proposed process of data and physics coupling for completion optimization and uncertainty reduction. Subsequently, Gaussian Process Model was used to explore optimization scenarios outside of the data region of confidence and to exploit the hybrid model to further reduce uncertainty and prediction. Overall, both the computation time to identify optimal completion scenarios and uncertainty were reduced. This technique creates a robust framework to improve operational efficiency and drive completion optimization in an optimal timeframe. The hybrid modeling workflow has also been piloted in other applications such as completion design, well placement and optimization, parent-child well interference analysis, and well performance analysis.
Zhong, Xun (Department of Petroleum Engineering, University of North Dakota) | Pu, Hui (Department of Petroleum Engineering, University of North Dakota) | Zhou, Yanxia (Department of Chemistry, University of North Dakota) | Zhao, Julia Xiaojun (College of Petroleum Engineering, Northeast Petroleum University)
Surfactant EOR received attraction due to its extreme capability to increase displacement efficiency by altering the wettability, lowering the oil/water interfacial tension and ultimately mobilizing the residual oil. However, surfactant systems are widely acknowledged to have large adsorption on rock/clay/sediment solid surfaces, which may result in concentration loss, thus impair the effectiveness of the chemical solution and turn the process into an economically unfeasible case. Surfactant adsorption can be affected by the adsorbents, surfactant structure, experimental temperature and some other factors. Also, the driving force for adsorption varies with different surfactants types. Generally speaking, electrostatic interaction is more prominent for those anionic surfactants, while hydrophobic interaction is more common for nonionic type.
In this paper, the static adsorption behaviors of two surfactants (A1 and N1) on Bakken minerals and Berea sandstone in high salinity and high temperature Bakken conditions (salinity≈290,000 mg/L, temperature=80~105 °C) were studied using spectrometric iodine method, where 0.1 mM I2-0.2 mM KI solution was used as a color developing agent. The primary stability indicated that both surfactants have high compatibility with the Bakken formation brine at high temperature, and their critical micelle concentrations showed a small decrease in the presence of high saline brine. Bakken mineral is relatively complicate, which is composed of quartz, dolomite, calcite and clay, while Berea sandstone contains over 75 wt% quartz. Herein, the effects of surfactant concentration, surfactant type, temperature, adsorbents and salinity on adsorption density were covered, and the impacts of surfactant concentration and adsorbents were found to be more significant. Due to the higher specific surface area and high clay content of Bakken minerals, both anionic surfactant blend A1 and nonionic surfactant blend N1 have pretty high adsorption on Bakken minerals, and the specific adsorption densities of 1000 mg/L surfactant solution were calculated to be 1.74 mg/m2 and 1.69 mg/m2, respectively. Meanwhile, the results also indicated that though the applied surfactant concentration is relatively low, the concentration loss due to adsorption should never be overlooked. Future study on how to effectively reduce the adsorption of surfactant especially in those clay-rich formations is of great significance.
The recent slump in oil prices has resulted in new terminology: “drilled uncompleted wells,” often referred to as DUC wells by the industry. In 2013 and 2014, when oil prices were more than USD 100/bbl, rate of return (ROR) from most unconventional plays was in the range of 15 to 50%, depending on the quality of rock and the operator’s portfolio in the basin. The objective of this paper is to address key challenges associated with DUC completions when they are eventually fractured and brought on line for production. The paper addresses four main concerns that can have significant impacts on productivity of DUC wells: fracture hits (well interference), reservoir quality (hydrocarbon drainage), multiple horizons (zone connectivity), and well spacing (high-density drilling). The paper also showcases case studies in which real-time observations made from wells have been used to validate predictions from forward-looking fracture and production models.
First, fracture hits commonly have been observed in all unconventional plays throughout the US, with effects on offset wells being mixed. Some fracture hits result in a positive uptick in production in offset wells, whereas other fracture hits affect production negatively in the form of increased water cut, reduced wellhead pressure, and other responses. Understanding fracture hits and their influence on other wells is very critical to avoid any detrimental impacts or to leverage positive effects on production. Second, reservoir quality decides how much oil in place is available for the DUC wells to drain, which, in turn, depends on length of production history and parent-well-completion geometries in offset wells. Third, in basins where there are multiple producing horizons or formations, fracture-height growth and interference between adjacent formations can result in asymmetric fracture propagation toward depleted zones. The longer these wells completed in the same/adjacent formations have been on production, the greater the extent of asymmetry will be. Addressing this concern requires a good understanding of drainage patterns from offset wells and evaluation of their impact on fracture geometries in DUC wells. Last, in areas with high-density drilling, a combination of longer production and fracturing stages with multiple perforation clusters per stage can leave very little oil available for the DUC well to produce.