This paper presents a multidomain integrated workflow that combines geophysics, borehole geology, fracture modeling, and petroleum systems analysis for characterization and resource assessment of basement plays. A 3D fracture model is developed by integrating image log interpretation and seismic data to assess the reservoir potential of fractured basement. The 3D fracture modeling is done using the discrete fracture network (DFN) approach with image log interpretation and other fracture drivers serving as the main input. The DFN is upscaled to generate fracture porosity and fracture permeability properties in a 3D grid. The upscaled fracture porosity is used to estimate the petroleum initially in place (PIIP) for the prospects. Multiple 2D petroleum system modeling is performed where large fault throws are identified from seismic interpretation. The petroleum system study helps in identification of areas with most prolific hydrocarbon generation and expulsion centers, which, coupled with the cross-fault juxtapositions, are the main locales of charging for basement reservoir. Further analysis of all the elements of basement play (i.e., source, reservoir, seal, trap, and migration) is done, and prospective areas within the basement play are delineated with high geological chance of success.
The significant temperature difference between the fractured and non-fractured regions during the stimulation fluid flow-back period can be very useful for fracture diagnosis. The recent developments in downhole temperature monitoring systems open new possibilities to detect these temperature variations to perform production logging analyses. In this work, we derive a novel analytical solution to model the temperature signal associated with the shut-in during flow-back and production periods. The temperature behavior can infer the efficiency of each fracture. To obtain the analytical solution from an existing wellbore fluid energy balance equation, we use the Method of Characteristics with the input of a relevant thermal boundary condition. The temperature modeling results acquired from this analytical solution are validated against those from a finite element model for multiple cases.
Compared to the warm-back effect in the non-fractured region after shut-in, a less significant heating effect is observed in the fractured region because of the warmer fluid away from the perforation moving into the fracture (after-flow). Detailed parametric analyses are conducted on after-flow velocity and its variation, flowing, geothermal, and inflow temperature of each fracture, surrounding temperature field, and casing radius to investigate their impacts on the wellbore fluid temperature modeling results.
The inversion procedures characterize each fracture considering the exponential distribution of temperature based on the analytical solutions in fractured and non-fractured regions. Inflow fluid temperature, surrounding temperature field, and after-flow velocity of each fracture can be estimated from the measured temperature data, which present decent accuracies analyzing synthetic temperature signal. The outputs of this work can contribute to production logging, warm-back, and wellbore storage analyses to achieve successful fracture diagnostic.
Computer vision (CV) techniques were applied to X-ray computed tomographic (CT) images of reservoir cores to evaluate their potential for rapidly identifying fractures and other lithologic/geologic characteristics. The analyses utilized feature-labeled CT cross sectional images, themselves distributed submillimeter voxels of density- and atomic number-sensitive CT Numbers, as inputs to a Fully Convolutional Neural Network (FCN) for semantic segmentation of reservoir core features. In FCN, an image is interrogated using a series of sliding windows at various scales to create weighted filters to reduce error between classes in training images. These networks of filter layers were used to assign probabilities of classes, which were upscaled back to the original image dimensions resulting in probabilistic class assignments onto each pixel. FCN model accuracy, defined by its ability to replicate manually-assigned labels in the raw (unannotated) training image stack, was at least 80% and generally improved with the size of the training set. Once the labels were assigned, the underlying feature frequency, orientation, and size were measured in 3D volume reconstructions using algorithms modified from standard image analysis software. This method allowed users to endow a classification model with subject matter knowledge for further, autonomous label prediction. Thus, while initial image annotation was labor intensive, subsequent images were rapidly classified once the model was built. The classified labels were analyzed for abundance, orientation, and size of fractures were calculated to characterize spatial information of these features. FCN combined with fracture labeling improved knowledge capture and automation of fracture identification. Models trained by high quality 3D datasets can greatly reduce the time needed to describe subsequent core. The method demonstrated is not limited to fractures, other lithologic/geologic features could be trained using the same method, which may result in additional efficiencies.
The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems.
The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
Fiallos Torres, Mauricio Xavier (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin) | Ganjdanesh, Reza (The University of Texas at Austin) | Kerr, Erich (EP Energy) | Sepehrnoori, Kamy (The University of Texas at Austin) | Miao, Jijun (SimTech LLC) | Ambrose, Raymond (EP Energy)
Optimizing spacing of infill wells and fractures can lead to large rewards for shale field operators, and these considerations have influences on primary and tertiary development of the field. Although several studies have been employed to show the existence of well interference, few models have also implemented Huff-n-Puff and injection containment methods to optimize further hydraulic fracture designs and pressure containment to improve the efficiency of Enhanced Oil Recovery (EOR). This study has performed a rigorous workflow for estimating the impacts of spatial variations in fracture conductivity and complexity on fracture geometries of interwell interference. Furthermore, we applied a non-intrusive embedded discrete fracture model (EDFM) method in conjunction with a commercial compositional reservoir simulator to investigate the impact of well interference through connecting fractures by multi-well history matching to propose profitable opportunities for Huff-n-Puff application. First, based on a robust understanding of fracture properties, updated production data and multi-pad wellbore image logging data from Eagle Ford, the model was constructed to perform nine wells sector model history matching. Later, inter-well connecting fractures were employed for enhanced history matching where results varied significantly from unmeasured fracture sensitivities. The result is the implementation of Huff-n-Puff models that capture inter-well interference seen in the field and their affordable impact sensitivities focused on variable injection rates/locations and multi-point water injection to mimic pressure barriers. The simulation results strengthened the understanding of modeling complex fracture geometries with robust history matching and support the need to incorporate containment strategies. Moreover, the simulation outcomes show that well interference is present and reduces effectiveness of the fracture hits when connecting natural fractures. As a result of the inter-well long fractures, the bottom hole pressure behavior of the parent wells tends to equalize, and the pressure does not recover fast enough. Furthermore, the EDFM application is strongly supported by complex fracture propagation interpretation and ductility to be represented in the reservoir. Through this study, multiple containment scenarios were proposed to contain the pressure in the area of interest.
The model has become a valuable template to inform the impacts on well location and spacing, completion design, initial huff-n-puff decisions, subsequent containment strategies (e.g. to improve cycle timing and efficiency), and to expand to other areas of the field. The simulation results and understandings afforded have been applied to the field satisfactorily to support pressure containment benefits that lead to increased pressure build, reduced gas communication, reduced offset shut-in volumes, and ultimately, improvements in net utilization and capital efficiency.
Unconventional oil and gas reservoirs are being explored significantly around the globe nowadays. The economical production of hydrocarbons from these unconventional oil and gas reservoirs like CBM requires very advanced and cost effective technologies. Hydraulic fracturing is such a technology which is being used in the oil and gas industry for many decades to create highly conductive channels in the formations having very low permeability values. Multistage hydraulic fracturing has been proved to be a great achievement in oil and gas industry to enhance the production from unconventional reservoirs. An effective hydraulic fracturing planning & execution is a key to achieve the expected results in terms of production from unconventional reservoirs such as tight gas, shale gas, coal bed methane or other very low permeability reservoirs.
Unconventional reservoirs such as Shale & CBM require large scale hydraulic fracturing operations, where multiple frac fleets, wire-line units, coiled tubing units; work-over rigs & ancillary services are mobilized. A scheduling software based project management approach was followed at CBM Raniganj for planning & modeling of operations. This paper aims to study how the operational resource deployed in Raniganj field for hydraulic fracturing was optimized in terms of time, cost & load for fracturing operations.
The approach of modeling & planning the hydraulic fracturing operations is based on project management & scheduling software. Assumptions were finalized based on experience. The loopholes, possible schedule slippages and other deterrents which could cause a lag in the hydro fracturing campaign aimed to pump over 1,600 frac jobs in CBM Raniganj field, over a period of 30 rig months, were identified clearly. The scope, time, budget & quality standards were clearly defined and a schedule was prepared with the help of the scheduling software to run the fleets in a clockwork manner. Activities like perforation, Acidizing, data fracturing, main fracturing, flowback, sand plug and finally sand cleanout were defined as series & simultaneous operation.
Nitrogen Cap Drilling (NCD) is a technique developed by Tengizchevroil (TCO) that enables drilling a highly fractured reservoir under conditions where more conventional pressurized mud cap drilling techniques are not viable. NCD is an extension of the closed hole circulating drilling (CHCD) technique (Ref SPE Paper # 79850) previously developed and used extensively by TCO for drilling a highly fractured carbonate reservoir where severe loss circulation is encountered and incurable.
CHCD is a pressurized mud cap drilling technique that relies on the ability to fill the well with a fluid density lighter than the reservoir pressure gradient in order to maintain communication with the reservoir pressure. Once the reservoir pressure gradient drops below the density of the lightest fluid available, the well will no longer support a full column of fluid to surface and an alternate drilling method must be employed.
TCO has developed NCD as a response to this operating reality in the Tengiz field. The NCD technique involves filling the annulus with a heavier than reservoir pressure gradient fluid once severe lost returns are encountered. The annulus fluid level does not reach the surface, and the resulting air gap is pressurized with nitrogen gas. This nitrogen "cap" is contained under the Rotating Control Device (RCD) which allows for maintaining pressure communication with the formation. Well status is continuously monitored by tracking the wellhead pressure and measuring the annulus fluid level. The bottom hole pressure is balanced by manipulating the composition of the annular fluid column and controlling the wellhead pressure.
In 2017, TCO conducted successful field trials and demonstrated that NCD is a viable technique to enable the continuation of the low reservoir pressure drilling program in Tengiz. TCO has since adopted NCD as the standard technique in wells where CHCD is not technically viable or operationally preferable. This paper will describe NCD technique development, equipment, procedures, operational implementation, and key learnings to date.
The expansion of unconventional resources development has placed emphasis on better understanding of hydraulic fracturing stimulation effectiveness and the area of pay affected by the fracture treatment to optimize well spacing and improve completion and stimulation effectiveness. Existing fracture diagnostic methods such as microseismic monitoring and tiltmeters do not provide information about fracture connectivity to the wellbore. In this paper, we present a chemical tracer flowback based fracture diagnostic and analysis methods to estimate the fractional contribution of each created fracture stage, which is open and connected to the wellbore to help improve field development strategies and provide valuable information on optimal well paths for future drilling and development. The findings out from the stage production contribution profiles using the chemical tracer technology allows engineers to improve stimulation efficiency in multistage hydraulic fracturing horizontal wells applications for completion optimization and production enhancement. Two case histories are presented in which the chemical tracer technology was applied to two horizontal wells. The results of the chemical tracer analysis were correlated to production data, reservoir parameter and other diagnostic tests. The resultant findings from the analysis help evaluate completion and stimulation effectiveness and determine the extent of inter-well connectivity of the fracture network and then used to optimize future completions in the region.
Inyang, Ubong (Halliburton) | Cortez-Montalvo, Janette (Halliburton) | Dusterhoft, Ron (Halliburton) | Apostolopoulou, Maria (University College London) | Striolo, Alberto (University College London) | Stamatakis, Michail (University College London)
Estimating the effective permeability and microfracture (MF) conductivity for unconventional reservoirs can be challenging; however, a new method for estimating using a stochastic approach is discussed. This new analysis method estimates matrix permeability and the unpropped and propped MF conductivities during laboratory testing where MFs were propped with ultrafine particles (UFPs).
Kinetic Monte Carlo (KMC) simulations form the basis of the method used to estimate effective permeability of the core sample. First, the stochastic model was implemented to calculate effective matrix permeability of a small core taken from unfractured Eagle Ford and Marcellus formation samples using scanning electron microscopy (SEM) images and adsorption data to obtain the pore-size distribution (PSD) within the sample. The KMC approach then evaluated the effect of various parameters influencing the conductivity of laboratory-created MFs. Case studies considered for this work investigate the conductivity improvement of a manmade MF as a function of the UFPs used as proppants that maintain width under high stress, the UFP (proppant) concentration, and the UFP flow perpendicular into a secondary or adjacent MF zone (2ndMF) penetrating the face of an opened MF during flow testing under stress. The leakoff area widths considered were 1, 2, and 3 mm and can be propped or unpropped.
Results obtained for the unfractured Eagle Ford and Marcellus samples closely correlate with other computational and experimental data available. For the laboratory-prepared nonpropped and propped MF samples, the effective propped width was determined to have the greatest effect on the MF conductivity, which increased by two orders of magnitude in the presence of the UFPs. The remaining two factors—proppant concentration and length of 2ndMFs—helped improve the effective MF conductivity in a linear manner; the highest proppant concentration and the 2ndMF zone resulted in the highest fracture conductivity achieved. Insight obtained from this study can be used to optimize fracturing designs by including UFPs and to create strategies for maximizing hydrocarbon recovery during development of unconventional resources where MFs are opened during stimulation treatments.
Shale plays are anisotropic in terms of their reservoir quality which gets reflected in their productivity. Reservoir qualities like organic richness, thermal maturity, hydrocarbon saturation, the volume of clay, brittleness and pressure affect the productivity of the shale plays. In general, the volume of clay has a negative relationship whereas other parameters listed above have a positive relationship with production. In our study area, we found the deepest wells despite having better rock quality; do not perform like nearby shallower wells. The objective of this study is to understand the not so obvious reason behind underperformance of these deepest wells.
Since the wells are located at a deeper depth and the reservoir temperature is high (90 to 135°C), so we studied the area from clay diagenesis and fluid expansion perspective. We have reviewed the imprints of clay diagenesis with the help of XRD data and core integrated multi min processed wireline logs. We observed an increasing trend of illite, chlorite towards the deeper part of the reservoir along with a decreasing trend of smectite in the same direction which indicates a higher degree of clay diagenesis. Fluid expansion study is carried out with the help of total organic carbon and hydrocarbon saturation. This study indicated a higher degree of fluid expansion (TOC to hydrocarbon generation) in the deepest part.
Subsequently, 1D pore pressure, stress and rock mechanical modeling is carried out to evaluate the effect of a higher degree of diagenesis and fluid expansion on geomechanical parameters (pore pressure, stress and brittleness). 1D modeling reveals that the deeper wells have abnormal pressure, stress and low brittleness, which is primarily due to extra pressure contribution from fluid expansion and clay diagenesis apart from the compaction disequilibrium process. This abnormal stress and reduction in brittlness likely to have created challenges for the applied hydrofrac job in the deepest part resulting to narrow frac geometry. Comparison of hydraulic fracture modeling between a shallow and the deepest wells reveal that the hydraulic fracture geometry in the deepest well is narrower than the shallower well. So we came to the conclusion that the deepest wells are underperforming than the shallower wells despite of their better rock quality due to ineffective fracturing and comparatively narrower fracture geometry.
The impact of clay diagenesis and fluid expansion in shale productivity has not been studied widely. Though many authors have extensively studied the impact of clay diagenesis on permeability and pore pressure, the integration of shale well production is rarely attempted. This work will help the operators to better analyze and understand their shale reservoir from clay diagenesis and fluid expansion point of view before planning the hydrofrac jobs.