Yuanfang Cheng

Mechanical Properties of Gas Shale During Drilling Operations

The mechanical properties of gas shale significantly affect the designs of drilling, completion, and hydraulic fracturing treatments. In this paper, the microstructure characteristics of gas shale from southern China containing up to 45.1% clay were analyzed using a scanning electron microscope. The gas shale samples feature strongly anisotropic characteristics and well-developed bedding planes. Their strength is controlled by the strength of both the matrix and the bedding planes. Conventional triaxial tests and direct shear tests are further used to study the chemical effects of drilling fluids on the strength of shale matrix and bedding planes, respectively. The results show that the drilling fluid has a much larger impact on the strength of the bedding plane than that of the shale matrix. The impact of water-based mud (WBM) is much larger compared with oil-based mud. Furthermore, the borehole collapse pressure of shale gas wells considering the effects of drilling fluids are analyzed. The results show that the collapse pressure increases gradually with the increase of drilling time, especially for WBM.

Simulating the effect of hydrate dissociation on wellhead stability during oil and gas development in deepwater

It is well known that methane hydrate has been identified as an alternative resource due to its massive reserves and clean property. However, hydrate dissociation during oil and gas development (OGD) process in deep water can affect the stability of subsea equipment and formation. Currently, there is a serious lack of studies over quantitative assessment on the effects of hydrate dissociation on wellhead stability. In order to solve this problem, ABAQUS finite element software was used to develop a model and to evaluate the behavior of wellhead caused by hydrate dissociation. The factors that affect the wellhead stability include dissociation range, depth of hydrate formation and mechanical properties of dissociated hydrate region. Based on these, series of simulations were carried out to determine the wellhead displacement. The results revealed that, continuous dissociation of hydrate in homogeneous and isotropic formations can causes the non-linear increment in vertical displacement of wellhead. The displacement of wellhead showed good agreement with the settlement of overlying formations under the same conditions. In addition, the shallower and thicker hydrate formation can aggravate the influence of hydrate dissociation on the wellhead stability. Further, it was observed that with the declining elastic modulus and Poisson’s ratio, the wellhead displacement increases. Hence, these findings not only confirm the effect of hydrate dissociation on the wellhead stability, but also lend support to the actions, such as cooling the drilling fluid, which can reduce the hydrate dissociation range and further make deepwater operations safer and more efficient.

Numerical analysis of wellbore instability in gas hydrate formation during deep-water drilling

Gas hydrate formation may be encountered during deep-water drilling because of the large amount and wide distribution of gas hydrates under the shallow seabed of the South China Sea. Hydrates are extremely sensitive to temperature and pressure changes, and drilling through gas hydrate formation may cause dissociation of hydrates, accompanied by changes in wellbore temperatures, pore pressures, and stress states, thereby leading to wellbore plastic yield and wellbore instability. Considering the coupling effect of seepage of drilling fluid into gas hydrate formation, heat conduction between drilling fluid and formation, hydrate dissociation, and transformation of the formation framework, this study established a multi-field coupling mathematical model of the wellbore in the hydrate formation. Furthermore, the influences of drilling fluid temperatures, densities, and soaking time on the instability of hydrate formation were calculated and analyzed. Results show that the greater the temperature difference between the drilling fluid and hydrate formation is, the faster the hydrate dissociates, the wider the plastic dissociation range is, and the greater the failure width becomes. When the temperature difference is greater than 7°C, the maximum rate of plastic deformation around the wellbore is more than 10%, which is along the direction of the minimum horizontal in-situ stress and associated with instability and damage on the surrounding rock. The hydrate dissociation is insensitive to the variation of drilling fluid density, thereby implying that the change of the density of drilling fluids has a minimal effect on the hydrate dissociation. Drilling fluids that are absorbed into the hydrate formation result in fast dissociation at the initial stage. As time elapses, the hydrate dissociation slows down, but the risk of wellbore instability is aggravated due to the prolonged submersion in drilling fluids. For the sake of the stability of the wellbore in deep-water drilling through hydrate formation, the drilling fluid with low temperatures should be given priority. The drilling process should be kept under balanced pressures, and the drilling time should be shortened.

Numerical investigation of fluid-driven debonding fracture propagation along wellbore interfaces during hydraulic fracturing

ABSTRACT The debonding of casing/cement or cement/formation interfaces are the representative forms of wellbore integrity failure. In this paper, a 3D finite element model for simulating the growth of fluid-driven debonding fractures along the casing/cement and cement/formation interfaces during hydraulic fracturing treatment is established. The simulation results show that (1) it is easier for the debonding fracture to extend along the casing/cement interface, (2) the fluid invasion induced debonding fractures will not cover the whole circumference of the interfaces, (3) the extent of uncovered circumferential region neighboring the debonding fracture gradually increases with the growth of the fracture height.

Modeling the Impact of Microinstrumentation in Microholes Wells and its Comparison with Conventional Casing

Microhole or slim hole drilling technique not only saves the time of drilling but also reduces the cost of drilling dramatically. The problem with this technology is its least technical acceptance due to wellbore stability of small-sized wellbores. The comparative analysis is conducted on three different wellbore models plotted against various yield strength pressures for conventional and microhole wells. Three categories of casing grades with different casing sizes were selected to develop the wellbore models, and the comparison categories include conventional wellbore (J-K-55), microhole wellbore (J-K-55), and microhole well (P-110). The result showed that magnitudes of different yield strength pressures are 90% higher in case of microhole (P-110) model. Additionally, surface axial stress is calculated to decide what type of casing is best fit for small-diameter wellbore, and the outcomes proved that higher-grade casings can yield stress 3110 psi. Further, overall comparison revealed P-110 casing grades possess higher yield strength pressure except yield strength of the pipe body; for this parameter, the phenomenon is inverse due to smaller difference of internal and external diameters. Henceforward, this paper focuses on suggesting the suitable casing grade for microholes that can yield more pressures and stay stable for longer period.

Experimental Research on Compressive Coefficient of Heavy Oil Reservoir in Bohai Bay Oil Field

In the process of heavy oil development, steam stimulation is usually used. In steam stimulation, the oil field is produced by depleted development after the end of shut in well. The magnitude of reservoir compressive coefficient is significant for the improvement of heavy oil recovery. The compressive coefficient of heavy oil reservoirs in Bohai oil field was tested by using self-designed servo control compressive coefficient equipment. It is found with the increase of the effective confining pressure; the core is gradually compacted and the resistance to deformation increases, so the compressive coefficient decreases with the increase of the effective confining pressure, and the decreasing rate decreases with the increase of the effective confining pressure. Due to the cementing, strength of the core with high porosity is lower, so it is easier to produce deformation under external load, and the compressive coefficient increases with the increase of the core porosity, but with the increase of the effective confining pressure, the difference of the compressive coefficient of the rocks with different porosities decreases. The experimental results provided an experimental support for the prediction of the production capacity of the heavy oil reservoir in Bohai oil field during the thermal recovery process.

Effect of liquid nitrogen cooling on the permeability and mechanical characteristics of anisotropic shale

Liquid nitrogen (LN2) fracturing is a promising new technology for unconventional reservoir simulation because it can effectively solve problems related to low permeability, low brittleness, and water shortage. The present work conducted a series of permeability and strength property-related experiments to evaluate the effect of LN2 cooling on the permeability and mechanical characteristics of anisotropic shale. The main findings of the study are as follows: (1) The influence of the bedding direction on the permeability of anisotropic shale cannot be eliminated by LN2 cooling. LN2 cooling could effectively increase the initial natural damage and the pore space of anisotropic shale, possibly increasing the volume of reservoir stimulation and provide more channels for the seepage and migration of oil and gas. (2) After LN2 cooling, the strength and brittleness of shale are obviously reduced, leading to the decrease in the ability of shale to resist deformation and failure, thereby helping to decrease the initiation pressure of reservoir stimulation. (3) The brittleness of shale will markedly increase during cryogenic fracturing, thus helping to form more complex fracture networks. Based on the present research, LN2 fracturing has obvious advantages compared with hydraulic fracturing in increasing the volume of reservoir stimulation. The results of this study are instructive for understanding the synergistic mechanism of LN2 fracturing and evaluating the effectiveness of reservoir simulation.

Numerical study of horizontal hydraulic fracture propagation in multi-thin layered reservoirs stimulated by separate layer fracturing

ABSTRACT Separate layer fracturing (SLF) technique is the prevailing method for stimulating multi-thin layered reservoirs (MTLRs) whereas the production record reveals that not all wells show good performance after being fractured. The primary cause for this phenomenon can be attributed to the complex geometry of the created hydraulic fractures. For better understanding the problem, we establish a new geomachanical model based on the extended finite element method (XFEM) and cohesive zone method (CZM), to investigate the fracture propagation in MTLRs under SLF. Reverse faulting stress regime is considered. In the simulation procedure, horizontal hydraulic fractures (HHFs) are created sequentially from the bottom up along a vertical wellbore. The results show that later created HHFs will propagate out of the pay zones or probably enter the water or gas-bearing layers if the fracturing time is not reasonably controlled. The fracture initiation pressure (FIP) and fracture propagation pressure (FPP) present larger values when stimulating the upper formations, and the deviation of later created HHFs can lead to the building up of FPP. Parametric studies indicate that larger injection rate and shallower reservoir depth yields longer and wider HHFs while smaller injection rate, shallower reservoir depth and thicker barriers results in lower FIP and FPP.

Effect of inter-cluster interference on fracture morphology in multi-cluster staged fracturing for shale reservoir

Multi-cluster staged fracturing technology is an effective measure to stimulate the reservoir properties. However, the inter-cluster interference effect is obvious when the cluster spacing is very narrow, which seriously affects the effect of fracturing. In order to understand the interference among fracturing clusters within the single fracturing section of the shale horizontal wells during multi-cluster staged fracturing, a finite element model is developed by using ABAQUS finite element simulation software. On this basis, the influences of factors on the fracture morphology are studied. The simulation results have shown that the cluster spacing is the most important factor affecting inter-cluster interference. With the increase in the distance between adjacent clusters, the interference among the fracturing fractures decreases and the propagation of different fractures become homogeneous or similar. Moreover, the increase in the elastic modulus of the shale formation promotes the propagation of the fractures longitudinally, but it hinders the crack opening of the fracture laterally. In addition, properly increasing the injection rate of fracturing fluid during fracturing is more advantageous for obtaining long and wide fractures. Besides, the effect of the fracturing fluid viscosity on fracture width is greater than that on the fracture half-length. The simulation results show the existence of inter-cluster interference comprehensively, which can provide a reference for the design and optimization of multi-cluster staged fracturing to some extent.

Establishment and evaluation of strength criterion for clayey silt hydrate-bearing sediments

ABSTRACT Appropriate strength criterion is the prerequisite for wellbore stability analysis. In this paper, the Modified Mohr-Coulomb criterion that considering the effects of hydrate is established based on the experimental results of the artificial clayey silt samples with hydrate. Meanwhile, the new criterion was evaluated by comparing the differences in the safe lower limit of drilling mud density calculated by both the traditional and modified Mohr-Coulomb criteria. The result demonstrates that the mud density window calculated by the new criterion is narrower, which reveals the applicability of the modified Mohr-Coulomb criterion in the analysis of wellbore stability in hydrate formation.