Effect of Drilling Fluid on Rock Mechanical Properties at Near-Drilling Conditions: An Implication of Fluid Design on Wellbore Stability

2016 ◽  
Author(s):  
Prahlad Kumar Yadav ◽  
Syed Shujath Ali ◽  
Najeeb Ahmed Al Tawat ◽  
Ali Abdullah Al Dhamen ◽  
Guodong Jin
Keyword(s):  
Mechanical Properties ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Fluid Design ◽  
Rock Mechanical Properties ◽  
Drilling Conditions

SUMHOLE DRILLING: WELLBORE STABILITY CONSIDERATIONS BASED UPON FIELD AND LABORATORY DATA

1996 ◽  
Vol 36 (1) ◽  
pp. 544
Author(s):  
M.A. Addis ◽  
R.G. Jeffrey
Keyword(s):  
Field Data ◽  
Drilling Fluid ◽  
Laboratory Data ◽  
Petroleum Industry ◽  
Cost Savings ◽  
Wellbore Stability ◽  
Wellbore Instability ◽  
Attractive Option ◽  
Different Diameters ◽  
Fluid Design

Slimhole drilling is becoming an attractive option as it provides significant cost savings in the petroleum industry. Furthermore, many of the technical obstacles in adapting slimhole drilling for the petroleum industry have been addressed, such as rig modifications, small volume kick detection, drilling fluid design, etc. However, wellbore stability in slimholes is largely taken for granted, when it could potentially increase costs dramatically. In this paper, a review of the available information on the effects of hole size on hole stability is presented. Wellbore stability in holes of different diameters is discussed qualitatively based on published laboratory data and unpublished field data. The quantitative assessment of wellbore instability in slimholes is addressed using observations of instability in a well in which the far field stresses were measured.The field data presented here suggest that slimhole wells are not more stable than conventional wells. The slimhole drilled in NSW shows that even using the most conservative prediction model, wellbore instability would not be predicted—instability was however, observed.

Realtime Drilling Geomechanics Aids Safe Drilling through Unstable Shales and Channel Sands of Wara Formations, Minagish Field, West Kuwait

2021 ◽  
Author(s):  
D.. Al Enezi ◽  
M.. AL Hajeri ◽  
S.. Gholum ◽  
S.. Nath ◽  
T.. Ahmad ◽  
...  
Keyword(s):  
Mechanical Properties ◽  
Bulk Density ◽  
Drilling Fluid ◽  
Poor Quality ◽  
Wellbore Stability ◽  
Quality Data ◽  
Earth Model ◽  
Empirical Correlations ◽  
Integrity Test ◽  
Pull Out

Abstract As part of any successful development plan of any hydrocarbon field, drilling boreholes safely is a key factor to make the entire process safe, economic and environmentally friendly. One of the main factors that dictates whether a borehole is going to be drilled safely or not is to understand the geomichanical behavior of the different formation to be penetrated. A definition of geomechanics could be stated as the science that studies the relationship between each of; in-situ stresses, rock mechanics, and the drilling fluid properties. In Kuwait and during the course of efforts to develop Wara channel sands in Minagish Field to the west of the country, Kuwait Oil Company (KOC) realized that continuing to drill development wells using conventional drilling practices is not any more an easy task. Considerable non-productive time has been recorded due encountering events such as shale carvings and pack off leading to stuck pipe. In addition, partial to total lost circulation were faced while drilling through Mutriba Formation which added to the complexity of problem. This study involved gathering data from offset wells to build a mechanical earth model for the area where the new well is going to be drilled. The main objective of having the model built is to perform wellbore stability analysis (WBS) and compute the quantitative mud window values to insure stable and safe borehole drilling. As the case of any study, performing reliable WBS analysis requires accurate modeling of earth stresses and rock mechanical properties. This process is primarily based on sonic logs (compressional and shear slowness), formation bulk density and lithology distribution. The study started with an audit of the available data sets in the region to select the best offset wells and generating empirical correlations to fill- up any missing and/or poor-quality data zones. Initially,7offset wells were identified, based on the geological distribution and data availability.Out of them, only four wells were found to have compressional slowness and three with bulk density measurements. However, it is worth mentioning that no shear slowness measurements were available in any of the offset wells in the region. Due to this, a correlation based compressional-shear relationship from nearby wells was proposed for the pre-drill study. The mechanical properties were characterized using the tri-axial core test results available from Wara and Burgan Formations. Empirical correlations were developed to obtain static mechanical properties from the dynamical mechanical ones and log responses. In addition, horizontal stresses in the region were constrained with formation integrity test data to have better control on the model. Finally, after the WBS model was built,it was compared to the available caliper data from the offset wells for calibration purposes. The resulted pre-drill geomechanics model was used to advise on the drilling parameters (mud weight) to be used in drilling the new development well. Moreover, and being the first realtime drilling geomechanics (RTDG) job in in Kuwait, an LWD sonic was used while drilling to supply the pre-drill model with realtime compressional and shear slowness measurements. Having the model updated in realtime with data from the formation at the borehole location resulted in optimizing the mud weight window limits by the geomechanics engineers as the well was being drilled. Following these mud weight recommendations based on the updated pre-drill model resulted in a smooth landing and horizontal sections in which all the wiper trips until the final pull out of hole were smooth.

Development Field First - Directionally Drilling Through Challenging Muderong Shale and Highly Depleted Reservoir Sand with HPWBM

2021 ◽  
Author(s):  
Tylan John Lambert ◽  
Shiv Aanand Mj ◽  
Courtney Clark
Keyword(s):  
High Performance ◽  
Chemical Interaction ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Robust Solution ◽  
Fluid Analysis ◽  
Well Design ◽  
Design Selection ◽  
Fluid Design

Abstract Advancement in High Performance Water Based Mud (HPWBM) coupled with a deeper understanding of shale and chemical interaction has taken a leap in recent years enabling the drilling of challenging wells whilst replacing Synthetic Based Mud (SBM) as the preferred technical option. The exceptional inhibition properties, versatility to chemical manipulation and stability, as well as being an environmentally beneficial alternative to SBM, HPWBM has proven to be a robust solution for drilling the challenging Muderong shale and highly depleted reservoir sands in the field. Through a detailed field wide offset review focusing on wellbore stability and shale reactivity relationship observations, time dependent shale reactivity and an engineered bridging package was the basis of a successful fluid formulation and selection which then resulted in a flawless execution of the challenging well. Various testing of shale cuttings from the field paired with an offset review was key to understanding the extent of shale reactivity in relation to the type of shale being drilled and cause of shale instability in the area. These results were imperative in providing technical justification to utilise HPWBM for drilling through the Muderong shale. Applying detailed reservoir drilling fluid analysis to the overburden drilling fluids design and incorporating previous offset fluid design learnings, provided a robust and versatile drilling fluid system. This paper will review the steps undertaken to validate the selection of HPWBM over SBM through detailed analysis of wellbore stability, shale reactivity, permeability assessment, pore throat sizing and pore pressure transmission. It will present the misnomer of comingling the wellbore stability requirement, primarily mud weight, with shale reactivity in the field as well as the relation between the plateauing of shale reactivity curves to near well wellbore swelling. Extensive laboratory testing was performed to formulate and demonstrate the efficacy of the bridging package in addressing differential sticking, losses and wellbore strengthening in highly depleted sands. In addition, this paper will also present actual field results on stability of the fluid properties along with resultant torque and drag throughout drilling of a directional well with no requirement for lubricants. This paper should be of interest to all engineers and technologists who are involved in shale reactivity analysis, well design, drilling fluids design, selection and interaction as well as highly depleted reservoir sand drilling.

scholarly journals New insight on studying the effect of both chemical sensitivity and rock mechanical properties in shale formation to minimize wellbore instability problems

2020 ◽  
Vol 205 ◽  
pp. 03012
Author(s):  
Mohammad H. Alqam ◽  
Hazim H. Abass ◽  
Abdullah M. Shebatalhmad
Keyword(s):  
Drilling Fluid ◽  
Wellbore Stability ◽  
High Porosity ◽  
Shale Formations ◽  
Wellbore Instability ◽  
Testing Procedures ◽  
Shale Formation ◽  
Rock Mechanical Properties ◽  
Core Volume ◽  
Shale Permeability

Historically, many of the wells drilled in in shale formations have experienced a significant rig downtime due to wellbore instabilities. Most of the instability problems originated from the encountered shale formations. The objectives of this study include (1) to measure the properties governing shale strength and drilling fluid/shale interaction, and (2) to establish a reliable and efficient rock mechanical testing procedures related to wellbore stability. Preserved shale core has been recovered from shale formation and special core handling procedure was implemented. Mineral oil was used for plugging and core preservation. Rock mechanical characterization was conducted on core samples using both XRD/SEM techniques to study the core mineralogy. In addition, shale permeability was determined by two methods: flow testing and pressure transition methods. The results indicated that shale has high percentage of quartz (30-40%) which causes the shale to have high porosity and high permeability. The unconfined compressive strength of shale is very low which any drilling fluid that contains water phase further reduces. The Young’s modulus is very low which makes near wellbore deformation high. Based on the shale swelling testing, the all-oil fluid show no volume change occurred to the shale. When the same shale was exposed to the 7% KCl, about 16% increase in core volume occurred in 48 hours. This means that all samples allowed the water to flow into the shale formation.

Mechanical properties of North Sea Tertiary mudrocks: investigations by triaxial testing of side-wall cores

Clay Minerals ◽  
1998 ◽  
Vol 33 (1) ◽  
pp. 171-183 ◽  
Author(s):  
L. Wensaas ◽  
P. Aagaard ◽  
T. Berre ◽  
E. Roaldset
Keyword(s):  
Mechanical Properties ◽  
North Sea ◽  
Drilling Fluid ◽  
Side Wall ◽  
Failure Criteria ◽  
Strength Properties ◽  
Wellbore Stability ◽  
Core Material ◽  
Elastic Behaviour ◽  
Triaxial Tests

AbstractIn the North Sea Tertiary section, wellbore instability problems are frequently reported in Palaeocene-Early Oligocene smectite-rich mudrocks. Analysis of the mechanical properties of these Tertiary mudrocks is generally hampered by the lack of suitable core material. This study represents an attempt to study the geomechanical behaviour of mudrocks by triaxial tests of side-wall cores obtained from the borehole wall. The tests performed include measuring the changes in pore pressure during shearing and undrained shear strength in specimens initially consolidated to in situ effective stress levels. The coefficients of permeability (kf), estimated from the consolidation time behaviour range from 2.6 x 10-11 to 2.4 x 10-12 m/s. The tested cores behaved like slightly overconsolidated to normally consolidated materials with an initial near constant volume (elastic behaviour) for low deviatoric load followed by an increasingly contractant behaviour approaching failure. Compared with results from onshore analogues, the strength properties of the investigated mudrocks appear to be related to their content of expandable clay minerals. A wellbore stability chart to forecast adequate drilling fluid pressures for future wells has been developed by the use of linear (Mohr-Coulomb) failure criteria based on the peak strength data. It is demonstrated that side-walt cores can provide satisfactory test materials for rock mechanical analysis, and their use may serve to improve our knowledge of the rock mechanical behaviour of typically troublesome mudrocks for which no conventional cores are available.

Geomechanical Properties Estimation Utilizing Artificial Intelligence Prediction Tool

2021 ◽  
Author(s):  
Mohammed Alabbad ◽  
Mohammad Alqam ◽  
Hussain Aljeshi
Keyword(s):  
Mechanical Properties ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Significant Loss ◽  
Wellbore Stability ◽  
Rock Properties ◽  
Ann Model ◽  
Full Field ◽  
Geomechanical Properties ◽  
Rock Mechanical Properties

Abstract Drilling and fracturing are considered to be one of the major costs in the oil and gas industry. Cost may reach tens of millions of dollars and improper design may lead to significant loss of money and time. Reliable fracturing and drilling designs are governed with decent and representative rock mechanical properties. Such properties are measured mainly by analyzing multiple previously cored wells in the same formation. The nature of the conducted tests on the collected plugs are destructive and samples cannot be restored after performing the rock mechanical testing. This may disable further evaluation on the same plugs. This study aims to build an artificial neural network (ANN) model that is capable of predicting the main rock mechanical properties, such as Poisson's ratio and compressive strength from already available lab and field measurements. The log data will be combined together with preliminary lab rock properties to build a smart model capable of predicting advance rock mechanical properties. Hence, the model will provide initial rock mechanical properties that are estimated almost immediately and without undergoing costly and timely rock mechanical laboratory tests. The study will also give an advantage to performing preliminary estimates of such parameters without the need for destructive mechanical core testing. The ultimate goal is to draw a full field geomechanical mapping with this tool rather than having localized scattered data. The AI tool will be trained utilizing representative sets of rock mechanical data with multiple feed-forward backpropagation learning techniques. The study will help in localizing future well location and optimizing multi-stage fracturing designs. These produced data are needed for upstream applications such as wellbore stability, sanding tendency, hydraulic fracturing, and horizontal/multi-lateral drilling.

scholarly journals Study on Wellbore Stability and Failure Regions of Shale considering the Anisotropy of Wellbore Seepage

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Fan Zhang ◽  
Houbin Liu ◽  
Yingfeng Meng ◽  
Shuai Cui ◽  
Haifeng Ye
Keyword(s):  
Mechanical Properties ◽  
Internal Friction ◽  
Drilling Fluid ◽  
Bedding Plane ◽  
Wellbore Stability ◽  
Borehole Wall ◽  
Distribution Model ◽  
Longmaxi Formation ◽  
Angle Of Internal Friction ◽  
Ground Stress

The hard and brittle shale formation is prone to collapse and instability, and the penetration of drilling fluid along the bedding reduces the mechanical properties of rock near the borehole wall, resulting in serious downhole accidents. Therefore, in this paper, the geomechanical parameters of the reservoir in the Longmaxi formation of Jiaoshiba were determined by field hydraulic fracturing and laboratory experiments. Then, the stress distribution model of borehole wall under the condition of underbalanced seepage flow is established based on the experimental results obtained by mechanical experiments on underground cores. The instability zone of borehole wall under the condition of underbalance is calculated and analyzed. The results show that the two-way horizontal ground stress of the Longmaxi formation is higher than 2.2 MPa/100 m, and the original ground stress is high. Moreover, the mechanical parameters of the stratified shale stratum matrix and weak surface are significantly different. The cohesion (4.7 MPa) and the angle of internal friction (26.9°) of bedding plane are significantly lower than that of the matrix (7.77 MPa) and the angle of internal friction (46.7°). Hard and brittle shale is easy to be destroyed along the stratification. Under the condition of underbalanced seepage, the mechanical properties of borehole shale can be stable. It is found that when the borehole axis is vertically stratified, the collapse pressure is the lowest, while in other drilling directions, the drilling fluid density needs to be increased by 0.5 g/cm3 to maintain the borehole stability. With the increase of the inclination angle of bedding plane, the wall failure area increases. The results of this study can provide guidance and suggestions for drilling in Jiaoshiba block and other permeable hard and brittle shale formations.

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%.

Interdisciplinary Approach for Wellbore Stability During Slimhole Drilling at Volga-Urals Basin Oilfield

2021 ◽  
Author(s):  
Anna Vladimirovna Norkina ◽  
Sergey Mihailovich Karpukhin ◽  
Konstantin Urjevich Ruban ◽  
Yuriy Anatoljevich Petrakov ◽  
Alexey Evgenjevich Sobolev
Keyword(s):  
Drilling Fluid ◽  
Interdisciplinary Approach ◽  
Wellbore Stability ◽  
Vertical Wells ◽  
Wellbore Instability ◽  
Water Based ◽  
Chemical Studies ◽  
Fluid Rheology ◽  
Selection Of

Abstract The design features and the need to use a water-based solution make the task of ensuring trouble-free drilling of vertical wells non-trivial. This work is an example of an interdisciplinary approach to the analysis of the mechanisms of instability of the wellbore. Instability can be caused by a complex of reasons, in this case, standard geomechanical calculations are not enough to solve the problem. Engineering calculations and laboratory chemical studies are integrated into the process of geomechanical modeling. The recommendations developed in all three areas are interdependent and inseparable from each other. To achieve good results, it is necessary to comply with a set of measures at the same time. The key tasks of the project were: determination of drilling density, tripping the pipe conditions, parameters of the drilling fluid rheology, selection of a system for the best inhibition of clay swelling.

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