Pressure Relief-Type Overpressure Distribution Prediction Model Based on Seepage and Stress Coupling

: At present, great progress has been made in the prediction of undercompaction and ﬂuid expansion overpressure. However, in recent years, the ﬁeld has frequently encountered pressure relief-type overpressure. Different from primary overpressure, such as undercompaction and ﬂuid expansion, this type of overpressure belongs to secondary overpressure, which has a certain conceal-ment in response to seismic velocity and logging data. Based on this, a geological analysis model of pressure relief-type overpressure was established according to the seepage and stress coupling theory. The model can realize the prediction of pressure relief range and pressure distribution, which provides a new way to predict this kind of overpressure. The inﬂuence of the laws of porosity, permeability, and geological movement on pressure relief were analyzed. The research results provide a new method for the prediction of pressure relief-type overpressure and improving the basic guarantee of safe and efﬁcient drilling.


Introduction
Formation pore pressure refers to the pressure of fluid (oil, gas, water) in the pores of rocks, also known as pore pressure or formation pressure. Normal pore pressure is equal to hydrostatic pressure from the continuous formation water from the surface to somewhere underground. Pore pressure higher than hydrostatic pressure is called abnormally high pressure. In drilling engineering, accurate determination of pore pressure is conducive to a reasonable selection of drilling fluid density and scientific design of the casing program, which can not only realize efficient and safe drilling but also protect the reservoir to the greatest extent.
There are a variety of pressure-forming mechanisms for abnormally high pressures. Swarbrick [1] classified the pore pressure formation mechanisms into three categories, including porosity reduction due to stress (including undercompaction and tectonic compression), fluid volume expansion (including hydrothermal pressurization, hydrocarbon generation, and mineral conversion), and fluid transport and buoyancy (including fluid transport, osmosis, water head, and buoyancy). It is pointed out that fluid migration in the same inclined reservoir or between different reservoirs may affect the identification of abnormal pressure formation mechanisms. Bowers [2] classified abnormally high pressure formation mechanisms into four categories, including undercompaction, fluid expansion (including hydrothermal pressurization, hydrocarbon generation, and mineral transformation), fluid migration, and tectonic compression. It is particularly emphasized that it is difficult to identify fluid migration and tectonic compression from well logging data, which should be combined with the history of tectonic movement. Ozkale [3] classified abnormally high pressure formation mechanisms into four categories, including undercompaction, fluid volume expansion (including hydrothermal pressurization, hydrocarbon generation, and mineral transformation), fluid migration and buoyancy (including fluid the prediction accuracy of pore pressure. The current development of VSP (vertical seismic profile) technology provides strong support for the application of this method. Honghai [17] further proposed an empirical model of acoustic velocity, taking into account the effects of porosity, mud content, and vertical effective stress, arguing that this model was suitable for sand and mudstone without the restriction of the undercompaction mechanism.
At present, a series of research achievements have been made in monitoring primary abnormally high pressure caused by undercompaction and fluid expansion. However, in recent years, pressure relief formation has been drilled frequently and the difficulty and error of pressure monitoring are extremely great, which leads to frequent field leakage and stuck drilling accidents that seriously affect casing depth and engineering safety. At present, the evaluation method of relief pressure formation is still based on the primary pressure evaluation method, that is, the Eaton and Bowers methods are used for evaluation on the basis of seismic and logging data. The adaptability of this method to abnormal pressure of the relief pressure formation is poor, so it is urgent to establish an effective evaluation method for the pressure of relief formation. Therefore, a pore pressure transfer model under the coupling effect of seepage and stress was established in this paper on the basis of well data and the distribution range of the pressure relief zone in the study area and its internal pressure distribution were determined, which can improve the foundation for pressure predictions for new drilling in this area.

Physical Model
Overpressure release is an effect of lowering abnormally high pressure to hydrostatic pressure. Overpressure release can be classified as complete and incomplete release. If a certain overpressure state is maintained after overpressure release, this is called incomplete release; otherwise, it is called complete release. Relief-type overpressure is the residual low amplitude overpressure after incomplete release.
There are many ways to release abnormally high pressure; the common ones are faults, cracks, sand bodies, etc. The result of pressure release leads to pressure redistribution in a certain range around the pressure release channel. In order to quantitatively describe the pressure relief range and the redistribution of pressure, the physical model of the pressure relief zone is simplified as shown in Figure 1: ment of VSP (vertical seismic profile) technology provides strong support for the a tion of this method. Honghai [17] further proposed an empirical model of acoustic ity, taking into account the effects of porosity, mud content, and vertical effective arguing that this model was suitable for sand and mudstone without the restriction undercompaction mechanism.
At present, a series of research achievements have been made in monitoring p abnormally high pressure caused by undercompaction and fluid expansion. Howe recent years, pressure relief formation has been drilled frequently and the difficul error of pressure monitoring are extremely great, which leads to frequent field l and stuck drilling accidents that seriously affect casing depth and engineering saf present, the evaluation method of relief pressure formation is still based on the p pressure evaluation method, that is, the Eaton and Bowers methods are used for e tion on the basis of seismic and logging data. The adaptability of this method to abn pressure of the relief pressure formation is poor, so it is urgent to establish an ef evaluation method for the pressure of relief formation. Therefore, a pore pressure t model under the coupling effect of seepage and stress was established in this paper basis of well data and the distribution range of the pressure relief zone in the stud and its internal pressure distribution were determined, which can improve the foun for pressure predictions for new drilling in this area.

Physical Model
Overpressure release is an effect of lowering abnormally high pressure to hydr pressure. Overpressure release can be classified as complete and incomplete relea certain overpressure state is maintained after overpressure release, this is called plete release; otherwise, it is called complete release. Relief-type overpressure is the ual low amplitude overpressure after incomplete release.
There are many ways to release abnormally high pressure; the common on faults, cracks, sand bodies, etc. The result of pressure release leads to pressure redi tion in a certain range around the pressure release channel. In order to quantitativ scribe the pressure relief range and the redistribution of pressure, the physical m the pressure relief zone is simplified as shown in Figure 1: The pressure zone after pressure relief can be divided into three parts: (1) p overpressure zone; (2) transition pressure zone; and (3) residual low amplitude ov sure area. The range of pressure relief can be quantitatively characterized by the fol parameters: (1) lateral pressure relief radius Rh: the horizontal distance from the The pressure zone after pressure relief can be divided into three parts: (1) primary overpressure zone; (2) transition pressure zone; and (3) residual low amplitude overpressure area. The range of pressure relief can be quantitatively characterized by the following parameters: (1) lateral pressure relief radius R h : the horizontal distance from the center point of the low amplitude overpressure layer to the boundary of the pressure relief range; (2) longitudinal pressure relief radius Rv: the vertical distance from the center point of the low amplitude overpressure layer to the boundary of the pressure relief range; and (3) pressure relief area S: In relatively homogeneous strata, the pressure relief area on the vertical profile is elliptical in shape, and its area is the pressure relief area.

Deformation
(1) Effective stress principle According to the effective stress principle, the deformation of the skeleton is only related to the effective stress. For saturated porous media, the effective stress is defined as: The effective stress coefficient can be expressed as: (2) Equilibrium equation The equilibrium equation of the skeleton is written as: (

3) Geometric equation
The geometric equation is: The strain coordination equation can be derived from Equation (4): (4) Constitutive equation The constitutive relation adopts the generalized Hooke's law: Or written as: If the commonly used elastic modulus E fr and Poisson's ratio v fr are used to express Equation (7), then: In this paper, the elastic modulus of the skeleton E fr and bulk modulus K fr of the skeleton were used to define the elastic properties of the formation. Equation (7) is written as follows: In combination with Equations (3) and (9), the equation can be written as: Equation (10) is the skeleton coupling elastic deformation equation. The coupling term of the fluid seepage effect is reflected in the first two terms of the equation. The stress used in the first two terms of the equation must be the effective stress, while the influence of body force, such as gravity, is reflected in the last term.
The above skeleton coupling deformation equations can only be solved by simultaneous seepage field equations.

Fluid Flow
According to the generalized Darcy's law, the relative velocity of the liquid v lr i is written as: Note that in order to distinguish the tensor index symbols i, j and the named symbols l, s, lr, and lT when a tensor requires both of these symbols, the tensor index symbols are uniformly written in the subscript and the named symbols are uniformly written in the superscript.
Since the mass of fluid flowing into the unit in unit time is equal to the increase in the liquid storage in the unit, the mass conservation equation of fluid is: Equation (12) can be further written as: If the pore pressure affects the fluid density, the derivative of fluid density concerning time can be written as: where α p is the compressibility coefficient of the fluid, defined as: Considering the dynamic change of porosity, there is: Or written as: If the influence of pore pressure and skeleton deformation on seepage is considered, at the same time, the coupling single-phase seepage equation can be obtained simultaneously by Equations (13), (14), and (17): In Equation (18), the second and third items on the right reflect the influence of skeleton deformation on seepage, the second item on the left reflects the influence of gravity, and the first item on the right reflects fluid compressibility. Equation (18) requires simultaneous skeleton deformation field equations to be solved.
In particular, when the flow velocity is large, the movement of the fluid gradually deviates from Darcy's law. At this time, the nonlinear seepage law should be adopted. Forchheimer's law is used to describe the general seepage process in the form of: The bold type in the formula represents the invariant notation of the vectors. The permeability coefficient k is defined as: Therefore, Forchheimer's law can also be written as: Permeability k of completely saturated porous media can be obtained through permeability experiments at low flow rates, which can be defined as a function of porosity.
Porosity can be derived from porosity, i.e., e = φ/(1 − φ). When the anisotropy of permeability is not considered, it is considered that the permeability is k in all directions. Due to formation sedimentation, it is sometimes necessary to consider the difference between horizontal and vertical permeability, which is recorded as k v and k h , respectively.

Model Establishment
In this paper, the geomechanical model of the whole study area was established based on the geological survey results of the area. Then, the magnitude and direction of tectonic stress and formation pressure values at certain test wells were calculated by trial calculations of different boundary displacements and relief layer pressures until they were in general agreement with the actual measured values. Finally, the stress and formation pressure fields corresponding to the model with the best fit of the calculated values to the measured values were taken as the final results.
The overall equilibrium equation of the model structure was: The stress was calculated as: Let there be N points within the model domain with measured stress values σ 1 (j), σ 2 (j), and σ 3 (j) assigned with the corresponding weight coefficients ω 1 (j), ω 2 (j), and ω 3 (j), respectively, according to the number of measurements and the confidence level. Using a certain constructive stress parameter T (determined by F) positive problem solution, the stress values were obtained as σ 1 (j), σ 2 (j), and σ 3 (j), considering T as a change point in m-dimensional space, i.e., T = T(T 1 ,T 2 ,T 3 , . . . ,T m ). Then, the sum of squares of the difference between σ(j) and σ 1 (j) (the fitting criterion) was: The magnitude of E(k) can then be used as a measure of whether T is realistic, such that the inverse problem was transformed into an optimization problem, i.e., finding T (or F) such that the optimality conditions were satisfied as: The constraints were taken as: The stresses and stress directions could be obtained by solving the above mechanical equations (by finite element means). In the actual study, the internal and external load method was mainly used, and the simulated values were optimally fitted to the measured values by adjusting the internal and external load values based on the established intrinsic structure model. Of course, the reasonableness of the results of ground stress inversion by the above method was mainly influenced by the following factors: (1) the shape and size of the geometric model; (2) the selection of the regional structural lattice; (3) the determination of the boundary conditions; (4) the selection of the mechanical model; and (5) the criterion of the best fit between the calculated and measured values.

Study Area
This paper, taking well block X as an example, aimed to calculate the pore pressure distribution on the profile of section A, determining the vertical and horizontal pore pressure relief range, namely the horizontal and vertical pore pressure relief radii, and the drainage area. Well block X was located at the northeast wing of the M structure in the central diapir zone of Ledong District, Yinggehai Basin ( Figure 2). Table 1 shows the basic technical data of the individual geological layers. The trap types of the Yinggehai and Huangliu Formations are mainly structural and lithologic traps.

Model Parameters
The geometric model of profile A was established, setting the initial porosity, initial permeability, Young's modulus, and Poisson's ratio to vary with space on the profile. The pressure profiles of wells X-1, X-2, and X-4 were taken as the constraint condition, using the method of steady-state seepage on profile A to establish the pressure balance of profile A and taking well X-3 as the verification well to verify the reliability of the model.
The software program Abaqus was used for the simulations with 270,000 finite elements and 271,331 nodes. The type of finite elements was CPE4P (a 4-node plane strain quadrilateral with bilinear displacement and bilinear pore pressure).
The boundaries of the left and right were only free in the vertical direction. The bottom of the geometric model possessed constraints in both vertical and horizontal directions. The pressure profiles of wells X-1, X-2 and X-4 were also used as constraints. The initial values of elastic modulus, Poisson's ratio, density, porosity, permeability, and pore pressure are shown in Figures 3-6.
The porosity, permeability, and density parameters near each well were given, and the parameters of the cross-well area were approximately replaced by the linear interpolation method. Taking well X-3 as an example, its initial porosity, permeability, and density are shown in Figure 3.
The change in formation pressure will lead to formation rock deformation and then affect the change in formation porosity and permeability. As shown in Figure 4, this paper considered the dynamic change in permeability with porosity. The solid line was an approximation of the actual survey.
As shown in Figure 5, the elastic model of well block X and Poisson's ratio change with depth are given.
According to the early drilling and completion data and correction, the pressure profiles of wells X-1, X-2 and X-4 are shown in Figure 6, and the pressures of these three wells were used as constraints. The traditional Eaton's method, based on the acoustic velocity data, was used to formulate the preliminary pressure profiles of wells X-1, X-2, and X-4, and the pressure test data using MDT (modular formation dynamics tester) were employed to determine the ultimate pressure profiles. Density (g/cm 3 ) Depth (km) Figure 3. Changes in initial porosity, permeability, and density with depth near well X-3.
The change in formation pressure will lead to formation rock deformation and then affect the change in formation porosity and permeability. As shown in Figure 4, this paper considered the dynamic change in permeability with porosity. The solid line was an approximation of the actual survey.  As shown in Figure 5, the elastic model of well block X and Poisson's ratio change with depth are given.  Density (g/cm 3 ) Depth (km) Figure 3. Changes in initial porosity, permeability, and density with depth near well X-3.
The change in formation pressure will lead to formation rock deformation an affect the change in formation porosity and permeability. As shown in Figure 4, this considered the dynamic change in permeability with porosity. The solid line was proximation of the actual survey.  As shown in Figure 5, the elastic model of well block X and Poisson's ratio c with depth are given. According to the early drilling and completion data and correction, the pressu files of wells X-1, X-2 and X-4 are shown in Figure 6, and the pressures of these thre were used as constraints. The traditional Eaton's method, based on the acoustic v data, was used to formulate the preliminary pressure profiles of wells X-1, X-2, a and the pressure test data using MDT (modular formation dynamics tester) w ployed to determine the ultimate pressure profiles. According to the early drilling and completion data and correction, the pressure profiles of wells X-1, X-2 and X-4 are shown in Figure 6, and the pressures of these three wells were used as constraints. The traditional Eaton's method, based on the acoustic velocity data, was used to formulate the preliminary pressure profiles of wells X-1, X-2, and X-4, and the pressure test data using MDT (modular formation dynamics tester) were employed to determine the ultimate pressure profiles.  Figure 6. Pressure profile of wells X-1, X-2, and X-4. Figure 6. Pressure profile of wells X-1, X-2, and X-4.

Model Validation
As shown in Figure 7, the reliability of the model was verified by the pore pressure calculation results of well X-3. It can be seen from the figure that the measured pressure value of the pressure relief layer and its lower part fell near the predicted value, indicating that the model was reliable. As shown in Figure 7, 14 MDT pore pressure test data were compared with the predicted pore pressure by the numerical models. The calculation error was approximately 3.32% at the depth of 3879 m. The pore pressure caused by the pressure relief of the sand body (coefficient = 1.46) kept a similar value and trend with the data in the literature (coefficient = 1.55) [18]. At present, the measured pore pressure data were relatively sparse and concentrated at two depths (3600 and 3800 m). More data at other depths (this well or near well) will be used for verification if field test data are collected.

Model Validation
As shown in Figure 7, the reliability of the model was verified by the pore pressure calculation results of well X-3. It can be seen from the figure that the measured pressure value of the pressure relief layer and its lower part fell near the predicted value, indicating that the model was reliable. As shown in Figure 7, 14 MDT pore pressure test data were compared with the predicted pore pressure by the numerical models. The calculation er ror was approximately 3.32% at the depth of 3879 m. The pore pressure caused by the pressure relief of the sand body (coefficient = 1.46) kept a similar value and trend with the data in the literature (coefficient = 1.55) [18]. At present, the measured pore pressure data were relatively sparse and concentrated at two depths (3600 and 3800 m). More data a other depths (this well or near well) will be used for verification if field test data are col lected.  Figure 8 shows the value of the pressure coefficient at any position on section A, a predicted by the coupled hydro-mechanical model. In this regard, obtaining the pore pres sure test data of drilled wells and determining the hydro-mechanical coupled parameter are important. Only in this way can the numerical model obtain reliable results. The tra ditional Eaton's method, based on the acoustic velocity data, was used to formulate the preliminary pressure profiles of wells X-1, X-2, and X-4, and the pressure test data using MDT (modular formation dynamics tester) were employed to determine the ultimate pressure profiles. The pressure profiles of wells X-1, X-2, and X-4 were used as constraints The pore pressure coefficients near all wells in Figure 8 Figure 8 shows the value of the pressure coefficient at any position on section A, as predicted by the coupled hydro-mechanical model. In this regard, obtaining the pore pressure test data of drilled wells and determining the hydro-mechanical coupled parameters are important. Only in this way can the numerical model obtain reliable results. The traditional Eaton's method, based on the acoustic velocity data, was used to formulate the preliminary pressure profiles of wells X-1, X-2, and X-4, and the pressure test data using MDT (modular formation dynamics tester) were employed to determine the ultimate pressure profiles. The pressure profiles of wells X-1, X-2, and X-4 were used as constraints. The pore pressure coefficients near all wells in Figure 8 showed the same values and trends compared with Figures 6 and 7. Figure 9 shows the pressure relief area around wells X-3 and X-2. Figure 9 shows an enlarged exhibit near wells X-3 and X-2 of Figure 8. The pore pressure coefficients near all wells in Figure 9 showed the same values and trends compared with Figures 6 and 7.

Results of Pore Pressure Relief
In combination with the above physical model, this paper quantitatively estimated the lateral pressure relief radius, longitudinal pressure relief radius, and pressure relief area around different wells (as shown in Figure 10). It can be seen from the figure that the lateral pressure relief radius on profile A was 3000~6000 m, the lateral pressure relief range near well X-4 was the largest, and the lateral pressure relief range near well X-3 was the smallest. The longitudinal pressure relief range was obviously smaller than the transverse pressure relief range, between 100~500 m, and the longitudinal pressure relief range near well X-3 was the largest. The pressure relief area was 100 × 10 4~8 00 × 10 4 m 2 , and the pressure relief area of well X-4 was the largest. The pressure relief range is related to the porosity and permeability characteristics around the well.  Figure 9 shows the pressure relief area around wells X-3 and X-2. Figure 9 shows a enlarged exhibit near wells X-3 and X-2 of Figure 8. The pore pressure coefficients near a wells in Figure 9 showed the same values and trends compared with Figures 6 and 7. In combination with the above physical model, this paper quantitatively estimate the lateral pressure relief radius, longitudinal pressure relief radius, and pressure relie area around different wells (as shown in Figure 10). It can be seen from the figure that th lateral pressure relief radius on profile A was 3000~6000 m, the lateral pressure relief rang near well X-4 was the largest, and the lateral pressure relief range near well X-3 was th smallest. The longitudinal pressure relief range was obviously smaller than the transvers pressure relief range, between 100~500 m, and the longitudinal pressure relief range nea well X-3 was the largest. The pressure relief area was 100×10 4~8 00×10 4 m 2 , and the pressur relief area of well X-4 was the largest. The pressure relief range is related to the porosit and permeability characteristics around the well.
The horizontal pressure relief radius depends on the sand body's horizontal distr bution, permeability, and pore pressure relief degree. A wider horizontal distribution  Figure 9 shows the pressure relief area around wells X-3 and X-2. Figure 9 shows an enlarged exhibit near wells X-3 and X-2 of Figure 8. The pore pressure coefficients near all wells in Figure 9 showed the same values and trends compared with Figures 6 and 7. In combination with the above physical model, this paper quantitatively estimated the lateral pressure relief radius, longitudinal pressure relief radius, and pressure relief area around different wells (as shown in Figure 10). It can be seen from the figure that the lateral pressure relief radius on profile A was 3000~6000 m, the lateral pressure relief range near well X-4 was the largest, and the lateral pressure relief range near well X-3 was the smallest. The longitudinal pressure relief range was obviously smaller than the transverse pressure relief range, between 100~500 m, and the longitudinal pressure relief range near well X-3 was the largest. The pressure relief area was 100×10 4~8 00×10 4 m 2 , and the pressure relief area of well X-4 was the largest. The pressure relief range is related to the porosity and permeability characteristics around the well.
The horizontal pressure relief radius depends on the sand body's horizontal distribution, permeability, and pore pressure relief degree. A wider horizontal distribution, higher permeability, or greater degree of pore pressure relief leads to a larger horizontal The horizontal pressure relief radius depends on the sand body's horizontal distribution, permeability, and pore pressure relief degree. A wider horizontal distribution, higher permeability, or greater degree of pore pressure relief leads to a larger horizontal pressure relief radius [19,20]. For the vertical pressure relief radius, the predicted data were approximate to the data shown in Figures 6 and 7. For the pressure relief area, these data could be calculated by the physical model of the pressure relief zone, as shown in Figure 1.
According to the model proposed in this paper, the undrilled pore pressure on section A could be predicted. Figure 11 shows the pore pressure prediction profile of an undrilled well, 3262 m to the left of well X-2. The pore pressure changes with depth showed the same trends compared with the two adjacent wells. It can be seen from the figure that there was no obvious pressure relief in this well and there was a small pressure relief between 3500 and 4000 m, so the density of drilling fluid within this depth range could be appropriately adjusted. pressure relief radius [19,20]. For the vertical pressure relief radius, the predicted data were approximate to the data shown in Figures 6 and 7. For the pressure relief area, these data could be calculated by the physical model of the pressure relief zone, as shown in Figure 1. According to the model proposed in this paper, the undrilled pore pressure on section A could be predicted. Figure 11 shows the pore pressure prediction profile of an undrilled well, 3262 m to the left of well X-2. The pore pressure changes with depth showed the same trends compared with the two adjacent wells. It can be seen from the figure that there was no obvious pressure relief in this well and there was a small pressure relief between 3500 and 4000 m, so the density of drilling fluid within this depth range could be appropriately adjusted.

Porosity and Permeability
The higher the porosity and permeability, the greater the degree of pressure relief This means that the wider the horizontal distribution of the sand body, the larger the lat eral pressure relief radius. The thicker the sand body, the larger the longitudinal relie radius.
Taking the well blocks X and N as examples for comparative analysis, it can be seen Figure 11. Prediction of the undrilled pore pressure profile.

Porosity and Permeability
The higher the porosity and permeability, the greater the degree of pressure relief. This means that the wider the horizontal distribution of the sand body, the larger the lateral pressure relief radius. The thicker the sand body, the larger the longitudinal relief radius.
Taking the well blocks X and N as examples for comparative analysis, it can be seen that the permeability of well block X was approximately 10 mD, while that of well block N was generally lower than 5 mD (Figure 12). The lateral pressure relief radius of well block X was approximately 3000~6000 m, while that of well block N was generally less than 800 m ( Figure 13). Therefore, permeability determined the influence range of pressure relief.
The higher the porosity and permeability, the greater the degree of pressure relief. This means that the wider the horizontal distribution of the sand body, the larger the lateral pressure relief radius. The thicker the sand body, the larger the longitudinal relief radius.
Taking the well blocks X and N as examples for comparative analysis, it can be seen that the permeability of well block X was approximately 10 mD, while that of well block N was generally lower than 5 mD (Figure 12). The lateral pressure relief radius of well block X was approximately 3000~6000 m, while that of well block N was generally less than 800 m ( Figure 13). Therefore, permeability determined the influence range of pressure relief.

Geotectonic Movement
The overpressure fluid in Yinggehai Basin was closed in the early stage and discharged intensively through the diapir in the late stage [21]. This paper analyzed the influence of diapir-induced fracture or hypertonic fracture opening on pressure relief. Taking the structure of well X-3 as an example, and referring to the pressure relief section monitored on-site, strata within the same depth range were intercepted for two-dimensional geological modeling, focusing on the pressure relief effect of lateral sand bodies and high permeability fractures and analyzing pressure changes in the formation before and after the opening of the diapir induced high permeability fractures ( Figure 14).

Geotectonic Movement
The overpressure fluid in Yinggehai Basin was closed in the early stage and discharged intensively through the diapir in the late stage [21]. This paper analyzed the influence of diapir-induced fracture or hypertonic fracture opening on pressure relief. Taking the structure of well X-3 as an example, and referring to the pressure relief section monitored on-site, strata within the same depth range were intercepted for two-dimensional geological modeling, focusing on the pressure relief effect of lateral sand bodies and high permeability fractures and analyzing pressure changes in the formation before and after the opening of the diapir induced high permeability fractures ( Figure 14).
ing the structure of well X-3 as an example, and referring to the pressure relief section monitored on-site, strata within the same depth range were intercepted for two-dimensional geological modeling, focusing on the pressure relief effect of lateral sand bodies and high permeability fractures and analyzing pressure changes in the formation before and after the opening of the diapir induced high permeability fractures ( Figure 14). The process of lateral pressure relief of the sandstone reservoir was simulated by using finite element simulation software. Figures 12 and 14 show the influence of porosity, permeability, and geological movement on pressure relief. A wider horizontal distribution, higher permeability, or greater degree of pore pressure relief led to a larger horizontal pressure relief radius. The results showed that the original high-pressure source in the sandstone reservoir released pressure due to the existence of transversely distributed high-permeability sand bodies and fractures at the boundary. The process of lateral pressure relief of the sandstone reservoir was simulated by using finite element simulation software. Figures 12 and 14 show the influence of porosity, permeability, and geological movement on pressure relief. A wider horizontal distribution, higher permeability, or greater degree of pore pressure relief led to a larger horizontal pressure relief radius. The results showed that the original high-pressure source in the sandstone reservoir released pressure due to the existence of transversely distributed high-permeability sand bodies and fractures at the boundary.

Summary and Conclusions
This paper proposed a pressure relief-type overpressure distribution prediction model based on seepage and stress coupling. A case study was conducted to numerically predict the pore pressure considering pore pressure relief using the finite element method. Several conclusions can be drawn, as follows: (1) A physical model of the pressure relief zone was established. The pressure zone after pressure relief can be divided into three parts: primary overpressure zone, transition pressure zone, and residual low amplitude overpressure area. The range of pressure relief can be quantitatively characterized by the following parameters: lateral pressure relief radius, longitudinal pressure relief radius, and pressure relief area.
(2) In the case study, the measured pressure value of the pressure relief layer and its lower part fell near the predicted value, indicating that the model was reliable. This paper quantitatively estimated the lateral pressure relief radius, longitudinal pressure relief radius, and pressure relief area around different wells, finding that the pressure relief range was related to the porosity and permeability characteristics around the well.
(3) The influence of the laws of porosity, permeability, and geological movement on pressure relief were analyzed, revealing that higher porosity and permeability led to a greater degree of pressure relief. The wider the sand body is horizontally distributed, the larger the lateral pressure relief radius. The thicker the sand body, the larger the longitudinal relief radius. The opening of the diapir induced hyperpermeability fractures that will result in formation pressure relief. The research results provide a new method for the prediction of pressure relief-type overpressure that will improve the basic guarantee of safe and efficient drilling of this kind of formation.