Simulating the effect of subsurface stresses and transient pore pressure on wellbore stability in subsea horizontal wells

2019 ◽  
Vol 41 (16) ◽  
pp. 2028-2038
Author(s):  
Ubedullah Ansari ◽  
Cheng YuanFang ◽  
Li QingChao ◽  
Georgia George Mawaipopo ◽  
Jia Wei
Keyword(s):  
Pore Pressure ◽  
Horizontal Wells ◽  
Wellbore Stability

The Essence of Horizontal Drilling Challenges in Depleted Reservoirs

2021 ◽  
Author(s):  
Rida Mohamed Elgaddafi ◽  
Victor Soriano ◽  
Ramadan Ahmed ◽  
Samuel Osisanya
Keyword(s):  
Pore Pressure ◽  
Horizontal Well ◽  
New Technology ◽  
Horizontal Wells ◽  
Stability Loss ◽  
Wellbore Stability ◽  
Planning Stage ◽  
Horizontal Drilling ◽  
Infill Drilling ◽  
Drilling Operations

Abstract Horizontal well technology is one of the major improvements in reservoir stimulation. Planning and execution are the key elements to drill horizontal wells successfully, especially through depleted formations. As the reservoir has been producing for a long time, pore pressure declines, resulting in weakening hydrocarbon-bearing rocks. Drilling issues such as wellbore stability, loss circulation, differential sticking, formation damage remarkably influenced by the pore pressure decline, increasing the risk of losing part or even all the horizontal interval. This paper presents an extensive review of the potential issues and solutions associated with drilling horizontal wells in depleted reservoirs. After giving an overview of the depleted reservoir characteristics, the paper systematically addresses the major challenges that influence drilling operations in depleted reservoirs and suggests solutions to avoid uncontrolled risks. Then, the paper evaluates several real infill drilling operations through depleted reservoirs, which were drilled in different oilfields. The economic aspect associated with potential risks for drilling a horizontal well in depleted reservoirs is also discussed. The most updated research and development findings for infill drilling are summarized in the article. It is recommended to use wellbore strengthening techniques while drilling a horizontal well through highly depleted formations. This will allow using higher mud weight to control unstable shales while drilling through the production zone. Managed Pressure Drilling should be considered as the last option for highly depleted formations because it will require a greater level of investment which is not going to have a superior rate of return due to the lack of high deliverability of the reservoir. Using rotary steerable systems is favored to reduce risks related to drilling through depleted formations. Precise analysis of different drilling programs allows the drilling team to introduce new technology to reduce cost, improve drilling efficiency and maximize profit. It is the responsibility of the drilling engineer to evaluate different scenarios with all the precautions needed during the planning stage to avoid unexpected issues. The present market conditions and the advancement in technologies for drilling horizontal wells increase the feasibility of producing the depleted reservoirs economically. This paper highlights the challenges in drilling horizontal wells in highly depleted reservoirs and provides means for successfully drilling those wells to reduce risks while drilling

Geomechanical Controls on Frac-Hits

2022 ◽  
Author(s):  
Dharmendra Kumar ◽  
Ahmad Ghassemi
Keyword(s):  
Pore Pressure ◽  
Fracture Propagation ◽  
Horizontal Wells ◽  
Operational Parameters ◽  
Modeling And Analysis ◽  
Matrix Deformation ◽  
In Situ Conditions ◽  
Fracture Fluid ◽  
Poroelastic Model ◽  
Element Method

Abstract The communication among the horizontal wells or "frac-hits" issue have been reported in several field observations. These observations show that the "infill" well fractures could have a tendency to propagate towards the "parent" well depending on reservoir in-situ conditions and operational parameters. Drilling the horizontal wells in a "staggered" layout with both horizontal and vertical offset could be a mitigation strategy to prevent the "frac-hits" issue. In this study, we present a detailed geomechanical modeling and analysis of the proposed solution. For numerical modeling, we used our state-of-the-art fully coupled poroelastic model "GeoFrac-3D" which is based on the boundary element method for the rock matrix deformation/fracture propagation and the finite element method for the fracture fluid flow. The "GeoFrac-3D" simulator fully couples pore pressure to stresses and allows for dynamic modeling of production/injection and fracture propagation. The simulation results demonstrate that production from a "parent’ well causes a non-uniform reduction of the reservoir pore pressure around the production fractures, resulting in an anisotropic decrease of the reservoir total stresses, which could affect fracture propagation from the "infill" wells. We examine the optimal orientation and position of the "infill" well based on the numerical analysis to reduce the "frac-hits" issue in the horizontal well refracturing. The posibility of "frac-hits" can be reduced by optimizing the direction and locations of the "infill" wells, as well as re-pressurizing the "parent" well. The results suggest that arranging the horizontal wells in a "staggered" or "wine rack" arrangement decreases direct well interference and could increase the drainage volume.

Impact of High Resolution 3D Geomechanics on Well Optimization in the Southern Gulf of Suez, Egypt

2021 ◽  
Author(s):  
Mohamed Elkhawaga ◽  
Wael A. Elghaney ◽  
Rajarajan Naidu ◽  
Assef Hussen ◽  
Ramy Rafaat ◽  
...  
Keyword(s):  
High Resolution ◽  
Pore Pressure ◽  
Cost Optimization ◽  
Oil Field ◽  
Wellbore Stability ◽  
Gulf Of Suez ◽  
Geomechanical Model ◽  
3D Geomechanical Model ◽  
The Cost ◽  
The Impact

Abstract Optimizing the number of casing strings has a direct impact on cost of drilling a well. The objective of the case study presented in this paper is the demonstration of reducing cost through integration of data. This paper shows the impact of high-resolution 3D geomechanical modeling on well cost optimization for the GS327 Oil field. The field is located in the Sothern Gulf of Suez basin and has been developed by 20 wells The conventional casing design in the field included three sections. In this mature field, especially with the challenge of reducing production cost, it is imperative to look for opportunites to optimize cost in drilling new wells to sustain ptoduction. 3D geomechanics is crucial for such cases in order to optimize the cost per barrel at the same time help to drill new wells safely. An old wellbore stability study did not support the decision-maker to merge any hole sections. However, there was not geomechanics-related problems recorded during the drilling the drilling of different mud weights. In this study, a 3D geomechanical model was developed and the new mud weight calculations positively affected the casing design for two new wells. The cost optimization will be useful for any future wells to be drilled in this area. This study documents how a 3D geomechanical model helped in the successful delivery of objectives (guided by an understanding of pore pressure and rock properties) through revision of mud weight window calculations that helped in optimizing the casing design and eliminate the need for an intermediate casing. This study reveals that the new calculated pore pressure in the GS327 field is predominantly hydrostatic with a minor decline in the reservoir pressure. In addition, rock strength of the shale is moderately high and nearly homogeneous, which helped in achieving a new casing design for the last two drilled wells in the field.

Revealing Hidden Information: High-Resolution Logging-While-Drilling Slowness Measurements and Imaging Using Advanced Dual Ultrasonic Technology

2021 ◽  
Vol 62 (1) ◽  
pp. 89-108
Author(s):  
Matthew Blyth ◽  
◽  
Naoki Sakiyama ◽  
Hiroshi Hori ◽  
Hiroaki Yamamoto ◽  
...  
Keyword(s):  
High Resolution ◽  
Elastic Wave ◽  
Horizontal Wells ◽  
Wellbore Stability ◽  
Frequency Range ◽  
Ultrasonic Technology ◽  
Logging While Drilling ◽  
Pulse Echo ◽  
Depth Of Investigation ◽  
Wave Properties

A new logging-while-drilling (LWD) acoustic tool has been developed with novel ultrasonic pitch-catch and pulse-echo technologies. The tool enables both high-resolution slowness and reflectivity images, which cannot be addressed with conventional acoustic logging. Measuring formation elastic-wave properties in complex, finely layered formations is routinely attempted with sonic tools that measure slowness over a receiver array with a length of 2 ft or more depending upon the tool design. These apertures lead to processing results with similar vertical resolutions, obscuring the true slowness of any layering occurring at a finer scale. If any of these layers present significantly different elastic-wave properties than the surrounding rock, then they can play a major role in both wellbore stability and hydraulic fracturing but can be absent from geomechanical models built on routine sonic measurements. Conventional sonic tools operate in the 0.1- to 20-kHz frequency range and can deliver slowness information with approximately 1 ft or more depth of investigation. This is sufficient to investigate the far-field slowness values but makes it very challenging to evaluate the near-wellbore region where tectonic stress redistribution causes pronounced azimuthal slowness variation. This stress-induced slowness variation is important because it is also a key driver of wellbore geomechanics. Moreover, in the presence of highly laminated formations, there can be a significant azimuthal variation of slowness due to layering that is often beyond the resolution of conventional sonic tools due to their operating frequency. Finally, in horizontal wells, multiple layer slownesses are being measured simultaneously because of the depth of investigation of conventional sonic tools. This can cause significant interpretational challenges. To address these challenges, an entirely new design approach was needed. The novel pitch-catch technology operates over a wide frequency range centered at 250 kHz and contains an array of receivers having a 2-in. receiver aperture. The use of dual ultrasonic technology allows the measurement of high-resolution slowness data azimuthally as well as reflectivity and caliper images. The new LWD tool was run in both vertical and horizontal wells and directly compared with both wireline sonic and imaging tools. The inch-scale slownesses obtained show characteristic features that clearly correlate to the formation lithology and structure indicated by the images. These features are completely absent from the conventional sonic data due to its comparatively lower vertical resolution. Slowness images from the tool reflect the formation elastic-wave properties at a fine scale and show dips and lithological variations that are complementary to the data from the pulse-echo images. The physics of the measurement are discussed, along with its ability to measure near-wellbore slowness, elastic-wave properties, and stress variations. Additionally, the effect of the stress-induced, near-wellbore features seen in the slowness images and the pulse-echo images is discussed with the wireline dipole shear anisotropy processing.

Best Practices in DFIT Interpretation: Comparative Analysis of 62 DFITs from Nine Different Shale Plays

2022 ◽  
Author(s):  
Mark Mcclure ◽  
Garrett Fowler ◽  
Matteo Picone
Keyword(s):  
Pressure Drop ◽  
Pore Pressure ◽  
Time Pressure ◽  
Early Time ◽  
Horizontal Wells ◽  
Late Time ◽  
Fracture Length ◽  
Well Spacing ◽  
Net Pressure ◽  
The Difference

Abstract In URTeC-123-2019, a group of operators and service companies presented a step-by-step procedure for interpretation of diagnostic fracture injection tests (DFITs). The procedure has now been applied on a wide variety of data across North and South America. This paper statistically summarizes results from 62 of these DFITs, contributed by ten operators spanning nine different shale plays. URTeC-123-2019 made several novel claims, which are tested and validated in this paper. We find that: (1) a ‘compliance method’ closure signature is apparent in the significant majority of DFITs; (2) in horizontal wells, early time pressure drop due to near-wellbore/midfield tortuosity is substantial and varies greatly, from 500 to 6000+ psi; (3) in vertical wells, early-time pressure drop is far weaker; this supports the interpretation that early- time pressure drop in horizontal wells is caused by near-wellbore/midfield tortuosity from transverse fracture propagation; (4) the (not recommended) tangent method of estimating closure yields Shmin estimates that are 100-1000+ psi lower than the estimate from the (recommended) compliance method; the implied net pressure values are 2.5x higher on average and up to 5-6x higher; (5) as predicted by theory, the difference between the tangent and compliance stress and net pressure estimates increases in formations with greater difference between Shmin and pore pressure; (6) the h-function and G-function methods allow permeability to be estimated from truncated data that never reaches late-time impulse flow; comparison shows that they give results that are close to the permeability estimates from impulse linear flow; (7) false radial flow signatures occur in the significant majority of gas shale DFITs, and are rare in oil shale DFITs; (8) if false radial signatures are used to estimate permeability, they tend to overestimate permeability, often by 100x or more; (9) the holistic-method permeability correlation overestimates permeability by 10-1000x; (10) in tests that do not reach late-time impulse transients, it is reasonable to make an approximate pore pressure estimate by extrapolating the pressure from the peak in t*dP/dt using a scaling of t^(-1/2) in oil shales and t^(3/4) in gas shales. The findings have direct practical implications for operators. Accurate permeability estimates are needed for calculating effective fracture length and for optimizing well spacing and frac design. Accurate stress estimation is fundamental to hydraulic fracture design and other geomechanics applications.

The Effects of Anisotropic Transport Coefficients on Pore Pressure in Shale Formations

2015 ◽  
Vol 137 (3) ◽  
Author(s):  
Vahid Dokhani ◽  
Mengjiao Yu ◽  
Stefan Z. Miska ◽  
James Bloys
Keyword(s):  
Pore Pressure ◽  
Fluid Transport ◽  
Drilling Fluid ◽  
Transport Coefficients ◽  
Electrical Potential ◽  
Three Dimensional ◽  
Bedding Plane ◽  
Wellbore Stability ◽  
Coupled Flow ◽  
In Situ Conditions

This study investigates shale–fluid interactions through experimental approaches under simulated in situ conditions to determine the effects of bedding plane orientation on fluid flow through shale. Current wellbore stability models are developed based on isotropic conditions, where fluid transport coefficients are only considered in the radial direction. This paper also presents a novel mathematical method, which takes into account the three-dimensional coupled flow of water and solutes due to hydraulic, chemical, and electrical potential imposed by the drilling fluid and/or the shale formation. Numerical results indicate that the presence of microfissures can change the pore pressure distribution significantly around the wellbore and thus directly affect the mechanical strength of the shale.

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