Hydraulic fracturing and horizontal drilling are keys to unlocking unconventional hydrocarbon resources. The efficiency and success of hydraulic fracturing require solid understanding of fundamental physics involved with injection so controlling factors can be identified and optimized for completion and operation designs.
This paper describes and quantifies critical geomechanical, geological, and engineering variables for fracture initiation and propagation in horizontal wells. Formation breakdown pressure and net pressure are evaluated and compared with varying rock stresses, laminations, and perforations. Recognizing each unconventional formation has its own geomechanical and geological characteristics, this study highlights the importance of adapting engineering designs to accommodate the formation difference.
Through analytical, numerical, and case studies, this paper finds the following:
These findings help advance the fundamental understanding of the physics involved in hydraulic fracturing processes. Results and learnings can be applied to optimize completion and operation designs, minimize horsepower requirements, and improve stimulation efficiency.
The mechanical properties of kerogen, the organic constituent of shale source rocks, change as it becomes progressively buried under sediment over geologic time. While these changes are due to both mechanical and chemical mechanisms, the individual impact of these mechanisms is poorly understood. In this work, we use atomistic models to isolate how the elastic properties of kerogen are affected by one of these mechanisms: changes in density due to mechanical compaction. We use atomistic models of kerogen at four different maturity levels – immature, top of the oil window, middle-end of the oil window, and over-mature. At each maturity level, we construct representative kerogen structures at densities ranging from 0.9 gm/cm3 to 1.5 gm/cm3 using molecular dynamics simulations. Subsequently, the elastic moduli are calculated at 0 K, 300 K, and 500 K using molecular statics and molecular dynamics simulations.
Kerogen exhibits an amorphous structure with a short-range order up to 6 Å and no discernable long-range order. Increases in kerogen density upon burial are accommodated by proportional increases in the stacking of poly-aromatic islands present in its structure. We show that the increased stacking leads to the formation of π-π stacking bonds, which correlates to the increases in the elastic moduli. We also find that Poisson's ratio measured from atomistic simulations changes linearly with changes in density but is invariant to changes in chemical composition. For all of these properties, the values measured via simulation show good agreement with results from nano-indentation, atomic force microscopy (AFM), and ultrasonic measurements.
These results are useful for several reasons. First, they provide an estimate of Poisson's ratio for kerogen over a range of densities and maturities. This estimate is useful in AFM and nano-indentation experiments, where Poisson's ratio is difficult to measure but is needed to calculate Young's modulus from the reduced modulus. Second, the results demonstrate how atomistic modeling can be applied to gain new insight into the relationship between kerogen structure and its mechanical properties. Third, the agreement between the elastic moduli measured via simulation and experiment shows that atomistic methods can be utilized to accurately characterize kerogen, which is important for building accurate rock models for hydraulic fracturing simulation. Finally, the atomistic models of kerogen developed in this work, constrained by their mechanical properties, can be employed to study other processes such as crack propagation and surface adsorption.
Resin coated proppant is used in hydraulic fracturing applications to stimulate oil/gas wells for production enhancement. The objective of this study was to perform a rock mechanical study to evaluate long term stability of RCP combined with various additives currently being used in screenless propped hydraulic fracturing completions in the sandstone formations to provide a tool for the industry to know exactly the duration of the shut-in time before putting well back in production. A new experimental method was developed to monitor the curing process of resin-coated proppant as temperature increases. The velocity of both shear and compressional waves were being monitored as a function of temperature. The tested resin of coated proppant sample has been housed in a pressurized vessel. The pressurized vessel was subjected to varying temperature profiles to mimic the recovery of reservoir temperature following propped hydraulic fracturing treatment. The placed proppant should attain an optimum consolidation to minimize proppant flow back.
Historically, sand production from poorly consolidated and unconsolidated sand formation, is a serious problem. These problems can lead to lost reservoir productivity, increased rates of required workover expenditure, fines plugging gravel packs, screens, perforations, tubulars and surface flow lines or separators. These problems hamper hydrocarbon production.
One of the major challenges, in comparing unconventional well performance during the appraisal phase, is the lack of long-term production data. In unconventional reservoirs, the main factor impacting well production is the generation of long effective fractures and large stimulated reservoir volumes (SRV). Different fracturing techniques are commonly tested during the appraisal phase, to find the best technique to maximize hydrocarbon recovery. Therefore a more robust methodology is required to analyze the production for a limited test period during the initial flow back.
This paper summarizes the application of the Rate Transient Analysis (RTA) to assist the selection of the best fracturing technique, through the estimation of the effective fracture length and a well potential index. The applied technique uses both the hydrocarbon and water production to characterize the initial fracture network performance. The implemented workflow factors in production data collection, flowing bottomhole pressure calculations, definition of fluid type at reservoir conditions and reservoir characteristics, and diagnostic plots generation. First, the methodology starts with calculating and plotting the rate normalized pseudo pressures vs. the square root of time for the total hydrocarbon rate and the equivalent plot for the water. If the wells were producing in a linear flow regime, the resultant slope of the straight line would provide the well potential index, which is a function of the product of the fracture half-length and the square root of the reservoir permeability. A calibrated permeability model from petrophysics was used as an input, to calculate the effective fracture half-length for each of the analyzed wells. These measured parameters allowed for the comparison of different fracturing techniques in a consistent framework.
The analysis was implemented in several wells where different frac techniques had been tested, among these were conventional crosslink, hybrid fracs, and slickwater. This methodology was successful on identifying which frac technique consistently provided the longest equivalent fracture half-lengths and SRV. It was found that the linear flow in the subject unconventional reservoir starts after a few hours of production, and extends up to the maximum produced time on the wells studied, which was 6 months. Results from pad well cases clearly confirmed the most effective stimulation strategy for the development scenario.
The workflow assists the completion optimization process during the appraisal phase for unconventional fields, where short production data is available. The proposed workflow helps production engineers in the decision-making process to select the best technique and perform initial flowback troubleshooting.
High pressure and high temperature (HPHT) oil and gas wells have rapidly become a regular occurrence over the last decade and continue to push the boundaries of technology development where enhanced elastomers and metallurgy for completion tools are required.
This paper delivers a clear approach to streamlined deployment and value-added techniques, which were utilized to successfully install the first HPHT openhole multistage fracturing system (MSF), combined with the first HPHT monobore liner hanger completion system. A major technical challenge is the identification and qualification of 15 Kpsi openhole multistage fracturing completion equipment, which is required for the successful exploitation of tight and unconventional HPHT reservoirs. The integration of two technologies from two service companies, qualified to overcome this requirement, called for unprecedented well planning; from engineering design assessment, systems integration appraisal, risk assessment with contingency planning to repeated modeling (geomechanic, drilling fluid, etc.), completion well on paper exercises, with planning improvements in well design and drilling equipment to achieve this breakthrough.
As with any technology, operational design, planning, and execution play key roles on many levels in ensuring successful deployment. This can only be achieved through stakeholder acceptance of relevant advanced technologies, globally accepted best practices, collaboration of industry experts and precise planning. This should be the case with any project deployed in the oil and gas industry, especially when technical specifications require working capabilities of 15 Kpsi and 375°F. With this breakthrough, the integrated 15 Kpsi multistage frac and monobore liner hanger completion technology was a suited application for a tight gas field.
The novel nanomaterial composition described in this paper has been designed to treat moderate to severe losses. The nanomaterial composition comprises an environmentally friendly nanoparticle based dispersion and a chemical activator. The design is based on a delayed activation chemistry to gel up a nanoparticle based dispersion.
Three different types of nanoparticles were used in the study to develop the novel loss circulation material. Two different types of negatively charged nanoparticle based dispersion and one positively charged nanoparticle based dispersion were used in the study. An inorganic activator has been used for the study. The effect of this inorganic activator on the gelation properties of the nanoparticle based dispersion was investigated. The gelling times were evaluated at different temperatures up to 300°F. The effect of activator concentration on the gelling time of the new composition has also been studied. The effectiveness of the newly developed composition as a loss circulation treatment was also evaluated by performing permeability plugging tests to test the plugging capacity of this novel system.
The novel nanomaterial composition is designed so as to have a controllable gelation time under a variety of downhole conditions to allow accurate placement of the treatment fluid inside the wellbore without premature setting of the fluid. It was shown that the gelation time of the treatment composition could be controlled by adjusting the concentration of the activator. The system is designed so as to give a predictable and controllable pumping time, ranging from a few minutes to several hours at over a wide range of temperatures. This is an important advantage as it allows the loss circulation composition to remain pumpable for sufficient time for placement and develops the network structure that leads to gelation, over a predictable period of time. The set gel, which appears as a crystalline solid, could remain homogenous and stay in place thereby preventing loss circulation.
Drilling in high pressure high temperature (HPHT) deep gas reservoirs, with multiple shallow different pressure horizons, requires special techniques which include application of Managed Pressure Drilling (MPD), revising casing setting depths, improving casing strength, and refining mud design. This paper focuses on application of MPD in HPHT gas wells and also describes briefly other techniques which can improve drilling performance and reduce nonproductive time.
Wellbore integrity is very critical in oil and gas industry and needs to be maintained through the entire cycle of well's life. The most important item for well integrity is to set cement between two casings or between casing and formation. A good cement job provides isolation and protection for the well and a poor cement job can have cracks and allows corrosive fluids to migrate through micro channels.
Downhole casing repair is a common workover operations worldwide, especially in wells that have been producing over number of years. It is very challenging to control corrosive fluid migration which slowly corrodes casing and tubing over time. An innovative epoxy resin formulations has been developed and tested in the field to repair casing leaks which is extremely easy to handle and very economical. A cost-effective workover program can be developed and implemented depending on the severity of the leak.
The improved approach of using innovative resin can be used by mixing with cement blends to repair major casing damage and can also be used as standalone application to fix minor leaks. The system maintains extremely good rheological properties even when mixed with cement. The system has ability to withstand high differential pressure and is also resistant to acid, salts, hydrocarbons and most importantly various corrosive liquids. The precise application is determined by measuring the injectivity of the well. In the low injectivity wells, only epoxy resin solution will be spotted and repair the damaged casing. In the high injectivity wells, the chemical will be mixed with cement and completely seal the damaged zone. The chemical will enhance the mechanical properties of the cement and will be more resilient to extreme down-hole condition.
The paper will emphasize the added value and potential of the method in restoring the casing integrity. The paper will also discuss the laboratory test reports and application which will highlight effective and economical outcome.
Three-dimensional unstructured grid generation for reservoirs with geological layers, faults, pinchouts, fractures and wells is presented. Grids are generated for example cases, and pressure fields and flow fields computed by the cell-centered and vertex-centered control-volume distributed multi-point flux approximation (CVD-MPFA) schemes are compared and contrasted together with the methods. Grid generation for reservoir simulation, must honour classical key geological features and multilateral wells. The geological features are classified into two groups; 1) involving layers, faults, pinchouts and fractures, and 2) involving well distributions. In the former, control-volume boundary aligned grids (BAGs) are required, while in the latter, control-point well aligned grids (WAGs) are required. In reservoir simulation a choice of grid type and consequent control-volume type is made, i.e. either primal or dual-cells are selected as control-volumes. The control-point is defined as the centroid of the control-volume for any grid type. Three-dimensional unstructured grid generation methods are proposed that automate control-volume boundary alignment to geological features and control point alignment to wells, yielding essentially perpendicular bisector (PEBI) meshes either with respect to primal or dual-cells depending on grid type. Both primal and dual-cell boundary aligned grid generators use primal-cells (tetrahedra, pyramids, prisms and hexahedra) as grid elements. Dual-cell feature aligned grids are derived from underlying primal-meshes, such that features are recovered, with control-volume faces aligned with interior feature boundaries. The grids generated enable a comparative performance study of cell- vertex versus cell-centered CVD-MPFA finite-volume formulations using equivalent degrees of freedom. The benefits of both types of approximation are presented in terms of flow resolution relative to the respective degrees of freedom employed. Stability limits of the methods are also explored. For a given mesh the cell-vertex method uses approximately a fifth of the unknowns used by a cell-centered method and proves to be the most beneficial with respect to accuracy and efficiency, which is verified by flow computation. Novel techniques for generating three-dimensional unstructured hybrid essentially PEBI-grids, honouring geological features are presented. Geological boundary aligned grid generation is performed for primal and dual-cell grid types. Flow results show that vertex-centered CVD-MPFA methods outperform cell-centered CVD-MPFA methods.
Hassan, Amjed (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Majed, Abdulaziz (King Fahd University of Petroleum & Minerals) | Al-Nakhli, Ayman (Saudi Aramco) | BaTaweel, Mohammed (Saudi Aramco) | Elktatany, Salaheldin (King Fahd University of Petroleum & Minerals)
Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution for condensate removal in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. Also, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal.
In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in-situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature, or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 hrs. of mixing and injection. Also, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used.
The results of this study showed that, the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure from the thermochemical reaction. These micro-fractures reduced the capillary forces that hold the condensate and enhanced its relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.