scholarly journals Wellbore Fracture Mode and Fracture Pressure Drilled in Depleted Reservoir

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Kai Zhao ◽  
Junliang Yuan ◽  
Ming Liu ◽  
Chuanliang Yan ◽  
Liangbin Dou ◽  
...  
Keyword(s):  
Fracture Mode ◽  
Drilling Fluid ◽  
Failure Criteria ◽  
In Situ Stress ◽  
Oil Fields ◽  
Tensile Failure ◽  
Fluid Loss ◽  
Fracture Pressure ◽  
Mud Loss

Drilling fluid loss in depleted reservoir has been an import issue faced by further tapping the potential of old oil fields. Accurate evaluation of the fracture pressure is the foundation to avoid mud loss. Traditional views suggest that tensile failure is the only fracture mode and the fracture pressure should be determined by a tensile failure criterion, which are not suitable for wells drilled in the depleted reservoir. In this paper, the analysis focuses on the fracture mode and fracture pressure in depleted reservoir, and case studies show that three fracture modes may first occur, and the fracture mode will be changed with reservoir depletion which highly depends on reservoir depletion degree, well azimuth and deviation angle, and the in situ stress state; different failure criteria at different stages of reservoir depletion should be selected to accurately evaluate the fracture pressure. For the vertical well, fracture pressure is no longer a single linear reduction with reservoir depletion; instead, a three-step and two-step reduction may appear, and for the directional well, the fracture pressure is not always decreased; the other patterns such as increase and first increase then decrease may also appear for the wells drilled in reverse and strike fault stress regimes.

Effect on Fracture Pressure by Adding Iron-Based and Calcium-Based Nanoparticles to a Nonaqueous Drilling Fluid for Permeable Formations

2016 ◽  
Vol 138 (3) ◽  
Author(s):  
Oscar Contreras ◽  
Mortadha Alsaba ◽  
Geir Hareland ◽  
Maen Husein ◽  
Runar Nygaard
Keyword(s):  
Drilling Fluid ◽  
Filter Press ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Fracture Pressure ◽  
High Pressure High Temperature ◽  
Iron Based ◽  
Wellbore Strengthening ◽  
Fracturing Experiments

This paper presents a comprehensive experimental evaluation to investigate the effects of adding iron-based and calcium-based nanoparticles (NPs) to nonaqueous drilling fluids (NAFs) as a fluid loss additive and for wellbore strengthening applications in permeable formations. API standard high-pressure-high-temperature (HPHT) filter press in conjunction with ceramic disks is used to quantify fluid loss reduction. Hydraulic fracturing experiments are carried out to measure fracturing and re-opening pressures. A significant enhancement in both filtration and strengthening was achieved by means of in situ prepared NPs. Our results demonstrate that filtration reduction is essential for successful wellbore strengthening; however, excessive reduction could affect the strengthening negatively.

A Novel Method to Determine the Drilling Fluid Density for Gypsum-Salt Layer

2021 ◽  
Author(s):  
Jitong Liu ◽  
Wanjun Li ◽  
Haiqiu Zhou ◽  
Yixin Gu ◽  
Fuhua Jiang ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Shrinkage Rate ◽  
Fluid Density ◽  
Salt Layer ◽  
Rock Creep ◽  
Key Factor ◽  
Well Abandonment

Abstract The reservoir underneath the salt bed usually has high formation pressure and large production rate. However, downhole complexities such as wellbore shrinkage, stuck pipe, casing deformation and brine crystallization prone to occur in the drilling and completion of the salt bed. The drilling safety is affected and may lead to the failure of drilling to the target reservoir. The drilling fluid density is the key factor to maintain the salt bed’s wellbore stability. The in-situ stress of the composite salt bed (gypsum-salt -gypsum-salt-gypsum) is usually uneven distributed. Creep deformation and wellbore shrinkage affect each other within layers. The wellbore stability is difficult to maintain. Limited theorical reference existed for drilling fluid density selection to mitigate the borehole shrinkage in the composite gypsum-salt layers. This paper established a composite gypsum-salt model based on the rock mechanism and experiments, and a safe-drilling density selection layout is formed to solve the borehole shrinkage problem. This study provides fundamental basis for drilling fluid density selection for gypsum-salt layers. The experiment results show that, with the same drilling fluid density, the borehole shrinkage rate of the minimum horizontal in-situ stress azimuth is higher than that of the maximum horizontal in-situ stress azimuth. However, the borehole shrinkage rate of the gypsum layer is higher than salt layer. The hydration expansion of the gypsum is the dominant reason for the shrinkage of the composite salt-gypsum layer. In order to mitigate the borehole diameter reduction, the drilling fluid density is determined that can lower the creep rate less than 0.001, as a result, the borehole shrinkage of salt-gypsum layer is slowed. At the same time, it is necessary to improve the salinity, filter loss and plugging ability of the drilling fluid to inhibit the creep of the soft shale formation. The research results provide technical support for the safe drilling of composite salt-gypsum layers. This achievement has been applied to 135 wells in the Amu Darya, which completely solved the of wellbore shrinkage problem caused by salt rock creep. Complexities such as stuck string and well abandonment due to high-pressure brine crystallization are eliminated. The drilling cycle is shortened by 21% and the drilling costs is reduced by 15%.

scholarly journals Experimental analysis of drilling fluid prepared by mixing iron (III) oxide nanoparticles with a KCl–Glycol–PHPA polymer-based mud used in drilling operation

2020 ◽  
Vol 10 (8) ◽  
pp. 3389-3397 ◽  
Author(s):  
Nayem Ahmed ◽  
Md. Saiful Alam ◽  
M. A. Salam
Keyword(s):  
Filter Cake ◽  
Drilling Fluid ◽  
Gel Strength ◽  
Filter Press ◽  
Plastic Viscosity ◽  
Fluid Loss ◽  
Drilling Mud ◽  
Drilling Operation ◽  
Critical Issues ◽  
Mud Loss

Abstract Loss of drilling fluid commonly known as mud loss is considered as one of the critical issues during the drilling operation as it can cause severe formation damage. To minimize fluid loss, researchers introduced numerous additives but did not get the expected result. Recently, the use of nanoparticles (NPs) in drilling fluid gives a new hope to control the fluid loss. A basic KCl–Glycol–PHPA polymer-based mud is made, and six different concentrations of 0.1, 0.5, 1.0, 1.5, 2.0, 3.0 wt% iron (III) oxide or Hematite (Fe2O3) NPs are mixed with the basic mud. The experimental observations reveal that fluid loss of basic mud is 5.9 ml after 30 min and prepared nano-based drilling mud results in a less fluid loss at all concentrations. Nanoparticles with a concentration of 0.5 wt% result in a 5.1 ml fluid loss at the API LTLP filter press test. On the other hand, nanoparticles with a concentration of 3.0 wt% enhance the plastic viscosity, yield point, and 10 s gel strength by 15.0, 3.0, and 12.5%, respectively. The optimum concentration of hematite NPs is found to be 0.5 wt% which reduces the API LPLT filtrate volume and filter cake thickness by 13.6 and 40%, respectively, as well as an improvement of plastic viscosity by 10%.

scholarly journals Quantitative characterization of collapse and fracture pressure uncertainty based on Monte Carlo simulation

2021 ◽  
Vol 11 (5) ◽  
pp. 2199-2206
Author(s):  
Sheng Ya-nan ◽  
Li Weiting ◽  
Jiang Jinbao ◽  
Lan Kai ◽  
Kong Hua ◽  
...  
Keyword(s):  
Monte Carlo Simulation ◽  
Monte Carlo ◽  
Rock Mechanics ◽  
In Situ Stress ◽  
Calculation Model ◽  
Quantitative Characterization ◽  
Fracture Pressure ◽  
Work Area ◽  
Geological Conditions

AbstractThe complex geological conditions of drilling, the difficulty of formation collapse and fracture pressure prediction in South Sichuan work area lead to the complex drilling and frequent failure, which seriously restricts the safe and efficient development of shale gas. In view of this problem, this paper has carried out relevant research. First of all, the existing calculation model of formation collapse and fracture pressure is established and improved; on this basis, the sources of uncertainty in the calculation model of collapse and fracture pressure are analyzed, mainly the in-situ stress and rock mechanics parameters, which have a lot of uncertainties; then, the uncertainty of rock mechanics parameters and in-situ stress is analyzed, and its probability is determined. Finally, based on Monte Carlo simulation, the quantitative characterization method of formation collapse and fracture pressure uncertainty is established. The prediction result of collapse and fracture pressure is no longer a single curve or value, but an interval, which is more practical for drilling in complex geological environment. The results of this study are helpful to better describe the collapse and fracture pressure of complex formation and can provide more valuable reference data for drilling design.

scholarly journals An Analytical Model for Fracture Initiation of Radial Drilling-Fracturing in Shale Formations

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Yuxin Chen ◽  
Yunhong Ding ◽  
Chong Liang ◽  
Yu Bai ◽  
Dawei Zhu ◽  
...  
Keyword(s):  
Failure Mode ◽  
Failure Modes ◽  
Shear Failure ◽  
Fracture Initiation ◽  
In Situ Stress ◽  
Tensile Failure ◽  
Shale Formations ◽  
Biot Coefficient ◽  
Radial Drilling

Abstract Radial drilling-fracturing, the combination of radial drilling and hydraulic fracturing, can guide fractures toward the target area and effectively enhance the recovery of the low permeable reservoir. In this paper, based on the stress superposition principle, we establish an analytical model to predict fracture initiation pressure (FIP) and the shale failure mode for radial drilling-fracturing applied in shale formations. In contrast with the former studies, this model can additionally consider the failure from shale beddings and is more applicable in the shale reservoir. The model classifies the shale failure into three modes and, respectively, gives the criterion for each failure mode. Then, a series of sensitivity analyses is conducted by examining effects of various parameters. By analyzing the variation characteristic of the initiation pressures required for three failure modes, the main conclusions are as follows. Firstly, matrix failure and shear failure along bedding tend to take place when the azimuth of radial borehole is moderate. Small and large azimuths are favorable for the occurrence of tensile failure along bedding. Secondly, a high ratio of horizontal in situ stress predisposes shale to generate matrix failure, and bedding tensile failure and bedding shear failure are apt to occur when the ratio of horizontal in situ stress is low. Thirdly, with the increasing intersection angle of the radial borehole wall and bedding plane, the failure mode apt to occur changes from bedding tensile failure to bedding shear failure and then to matrix failure. Fourthly, shale prefers to yield bedding shear failure under a small Biot coefficient and generate the other two failure modes when Biot coefficient is large. Fifthly, permeability coefficient virtually has no influence on the failure mode of shale. The research clarifies the fracture initiation characteristics of radial drilling-fracturing in shale formations and provides a reference for the field application of radial drilling-fracturing.

Spatio-Temporal Stress Path Prediction Under Different Deformational Conditions

2017 ◽  
Author(s):  
Saeed Rafieepour ◽  
Stefan Z. Miska
Keyword(s):  
Boundary Conditions ◽  
Flow Regime ◽  
Plane Strain ◽  
Stress Path ◽  
In Situ Stress ◽  
Uniaxial Strain ◽  
Fracture Pressure ◽  
Stress Changes ◽  
Path Prediction

Drilling new infill wells in depleted reservoirs is extremely problematic and costly due to low formation fracture pressure and narrow mud window resulting from in-situ stress changes due to fluid extraction. This is of paramount importance especially for drilling operations in deep-water reservoirs, which requires precise prediction of formation fracture pressure. In turn, this entails accurate prediction of reservoir stress changes with pore pressure depletion, i.e., the stress path. Currently-used models assume a transient flow regime with reservoir depletion. However, flow regime in depleted reservoirs is dominantly pseudo-steady state (PSS). Shahri and Miska (2013) proposed a model under plane-strain assumption. However, subsea subsidence measurements confirm that depletion-induced reservoir deformation mainly occurs in axial direction. We provide analytical solutions for stress path prediction under different deformational conditions namely, plane strain-traction and displacement boundary conditions, generalized-plane-stress, generalized uniaxial strain, and uniaxial-strain. For this purpose, constitutive relations of poroelasticity are combined with equilibrium equations, and pore pressure profile is described by PSS flow regime. In a numerical example, we examine the effects of different deformational conditions on depletion-induced in-situ stress changes. Interestingly, results indicates that stress path in reservoir is significantly affected by reservoir’s boundary conditions. The stress path under plane strain-displacement assumption overestimates the stress path predicted under uniaxial strain state by almost a factor of two. However, the generalized plane stress and traction plane strain conditions underestimates the results of uniaxial strain assumption. The order of stress path values for different boundary conditions can be summarized as: SPps-disp > SPuniaxial > SPps-trac > SPgps.

Cylindrical Borehole Failure in a Poroelastic Medium

2016 ◽  
Vol 83 (6) ◽  
Author(s):  
Yue Gao ◽  
Zhanli Liu ◽  
Zhuo Zhuang ◽  
Keh-Chih Hwang ◽  
Yonghui Wang ◽  
...  
Keyword(s):  
Shear Failure ◽  
Hydrostatic Stress ◽  
Drilling Fluid ◽  
Constitutive Relations ◽  
Three Dimensional ◽  
Tensile Failure ◽  
Porous Rock ◽  
Long Time ◽  
Poroelastic Model

Drilling a cylindrical borehole is the first and important step in oil mining. Borehole design and strength check are big problems of utmost importance. Biot introduced a poroelastic constitutive theory for porous rock with freely moving fluid inside. In this paper, by using Biot poroelastic model, we analyze a borehole with drilling fluid in an infinite porous rock with three-dimensional in situ stresses and obtain whole domain solutions for instantaneous, short-time, and long-time stress distributions. Maximum and minimum allowable drilling pressures are given for tensile failure and shear failure criterions, and allowable drilling pressure regions are drawn in the space of in situ hydrostatic stress P0, deviatoric stress S0, and pore pressure p0. By comparing with classical elastic constitutive relations, or Hooke's model, the necessity of Biot poroelastic constitutive relations is shown.

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