Understanding the Mechanisms of Drilling Challenges through a Systematic Risk Assessment and Geomechanics Modeling; a Post-Drill Case Study,

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Introduction
A lot of drilling challenges experienced throughout drilling the reservoir interval within Balsam field, Onshore East Nile Delta, so based on the available data; the study aims to delineate the troublesome zones, understand the root causes of the drilling challenges and provide mitigation plan for the future wells through an integration between risk assessment and geomechanics modeling that would be beneficial to properly understand the root causes and assist in delivering an optimum solution for drilling activities in the same filed and/or geological age.
The structural analysis of the seismic maps of the Nile Delta Basin exhibited the presence of two main structural high trends.The first trend is found in the northeastern part of the Nile Delta block.The long axis of this structure with NW trend, is bounded to the east by a cluster trending fault throwing down to the SW towards the center North Nile Delta basin, and plunges to the NW.The second one is located in the northwestern part of the Nile Delta basin (Sarhan and Hemdan, 1994).
The Nile Delta Basin experienced a major regression during the Late Miocene along with the rest of the Mediterranean, with deposition of evaporitic deposits of Rosetta Formation and fluvial to marginal marine facies deposited in deep incised valleys forming Abu Madi Formation.During the Early Pliocene, the sea level started to rise giving way to a generalized transgression bringing bathyal facies above the restricted Messinian units.The overall sedimentary pattern of the Plio-Pleistocene succession of the Nile Delta is characterized by a dominant progradation with large scale clinoforms and an evident northward migration of the shelf break; nevertheless, some back stepping phases occurred (Abdel Aal et al., 1994).
The tectonic movements affected the Nile Delta are extended from Late Eocene to Recent and dominated by three trends.The first trend is the Late Eocene to Miocene Gulf of Suez trend including the NNW trending normal faults.These faults are parallel to the Gulf of Suez rift and observed in the central Nile Delta.The second one is related to the development of the Miocene-Recent Gulf of Aqaba rift (Abdel Aal et al., 1994 &2001).
The reservoirs of Egypt's Nile Delta area are very complex.Therefore, they require more sophisticated methods of characterization and evaluation, especially the thinly laminated reservoirs.New technologies, such as Magnetic Resonance Log (MRIL) data acquisition and post-processing, can help provide more identification of these reservoirs.To obtain good porosity and permeability profiles for the thinly laminated reservoirs, the MRIL post-processing data should be used with enhanced vertical resolution to help ensure thinly bedded reserves are not overlooked and for integrating both the core and the image data used to confirm the presence and evaluation of these thin laminations (Reda et al., 2009).
The usage of velocity-density cross-plots is for identifying the causes of overpressure in Malay basin.This study integrates geophysical, geological, and drilling data of multiple wells across the region and has tried to develop an in-depth knowledge of geomechanical aspects of the basin.Both well-centric and field-wide observations have been made based on advanced acoustics, imaging, drilling and geochemical data (Hoesni, 2004, Pathy et. al., 2016).The integrity of the borehole plays a significant part in many well operations.
During drilling, lost circulation and borehole collapse cause economic losses, and in production operations, controlled fracturing and sand control are of utmost importance for the economy of an oil field.a complete geomechanical model have to be developed that takes into account all directional properties (Paul et al., 2014).
In similar formation conditions and petrophysical characteristics, several benefits were observed with the addition of bridging/sealing agent to either HPWBM (High performance water based mud) and/or OBM (oil-based mud) that minimized hole washout; enhanced wellbore quality; enhanced depleted sand integrity.Proper understanding of drilling challenges resulted in an improved drilling curve, reduced cost, stable and gauge hole, reduction in mud losses, and reduction in total NPT (nonproductive time).Although a net improvement was achieved and most of the field project objectives were met, it is believed that there is still room to improve the fluid system via assistance of Geomechanical analysis.Further work on understanding the damage due to nanoparticles in reservoir units needs to be undertaken to ensure the advantages to drilling are not cancelled out by formation damage in tight formations (El Sherbeny et al., 2014).
Regardless mud type, implementing a proper bridging methodology utilizing lab work like Particle Plugging Apparatus (PPA), Particle Size Distribution (PSD) along with specialty software will help to minimize geomechanical related troubles such as partial losses and differential sticking.
The same approach could help in avoiding an excessive invasion and pressure transmission through micro-fractured formation utilizing deformable sealing polymer (DSP) along with bridging materials such as calcium carbonate and synthetic graphite.
KCl % ( Potassium Chloride) by wt at 5 -7 % by wt still adequate to help in stabilizing shaly formations along with other High-Performance Water Based Mud inhibitive package.High Performance Water Based Mud phase salinity should match connate water salinity of drilled formations to ensure adequate wellbore stability.Due to possibilities of caved shale, so a sort of software should be utilized to optimize mud rheology to maintain a proper hole cleaning while drilling especially for deviated wells where cutting bed build up is applicable (Abdallah et al., 2015).
Natural lost circulating materials such as Prosopis farcta acts much better than the most commonlyused conventional LCM, CaCO3 in term of filtrate control since the filtrate will be reduced by 76% with only 15 ppb of the fine sized PF while in order to reduce the filtrate by 47%, 20 ppb of the CaCO3 will be required (which means higher solid contains).In addition to that the PF ( Prosopis farcta) overcomes the CaCO3in term of availability, cost, naturality and environmente (Jaf, et al., 2023).
Effective geomechanical analysis involves integration of results extracted from the different data sources, in conjunction with various geomechanical modeling techniques to identify complex drilling problems, and results in fit-for-purpose solutions (Imtiaz et al., 2017).
An integrated approach utilized to properly understand drilling challenges in certain gas fields in Saudi Arabia that experienced differential sticking due to excessive overbalance.The integrated approach of using geomechanics and drilling risk assessment showed successful achievement to understand the drilling difficulties root causes and deliver the well without any instability issues (Hamid et al., 2018).
Wells drilled in the direction of minimum stress are potentially more favorable for reservoir development and optimal production.In such a situation, hydraulic fractures grow transversely to the wellbore axis, allowing placement of multiple fractures without the overlapping fractures.However, wells that have been drilled in the minimum horizontal stress direction typically encounter drillingrelated problems such as stuck pipe, wellbore breakout and lost circulation (Addagalla et al., 2018).
The most important parameter influencing the drilling fluid loss process and subsuqentely wellbore stability is equivalent circulating density (ECD) versus formation pressure, so by controlling ECD values we will be able to minimize the overbalance drilling reducing the risk of getting downhole losses and wellbore stability ( Salih and Abdul Hussein, 2022).
Time-dependent failures in shaley sections of Kafar El Sheikh, Abu Madi, Qawasim formations might be due to invasion and pressure transmission through both sandstone and shale lithologies, respectively as some of the wells experienced challenges during both pull out of hole and wireline runs.The drilling challenges still persist however a different drilling fluid types utilized and tried in the field such as Bridge Sal Ultra, KCl/polymer mud, Silicate Mud, KCl/ Silicate mud and KCl/ Glycol mud (El Sherbeny et al., 2022).
Drilling formations of different pore pressure regime is very risky and might result in a lot of wellbore instabilities challenges, reservoir damages and eventually affecting the drilling operations and production schedule, so the need for optimum wellbore strengthening arises and it requires an information about reservoir permeability, porosity, pore throat sizes and fracture apertures besides reservoir pressures (El Sherbeny et al., 2023).
Based on the available data, a risk identification built along with 1D geomechanical model to identify the risk, ranking the risk, properly delineate the troublesome intervals and eventually understand the main root causes related to drilling difficulties specially through the reservoir section.Such kind of study normally considered as an economic one that in turn help operators to drill through same geological age with minimal challenges minimizing the non-productive time and accelerate the well delivery process.The study results will also helps to optimize the drilling practices and drilling fluids selection and design for future wells to ensure more stable wellbore with very minimal reservoir damages possibilities.

Study Area & Exploration History
Balsam field is onshore field located in the Nile Delta region, West El Manzala Concession between Longitudes 30° and 32°E, and Latitudes 30° and 32°N (Fig. 1).Since 2012, eight wells had been drilled targeted the Upper Miocene Qawasim Formation at depth +/-3200 m.This formation is an important hydrocarbon reservoir in the Nile Delta Province.Balsam-1 drilled as an exploratory deviated well on November

Data Inventory
Three wells had been considered in the study based on the available and received data from the operator.The available data includes all electric logs (gamma rays, acaustic, resistivity, Density-Neutron, Caliper data) in additions to borehole images, drilling reports, so based on the available data Balsam-2_2, Balsam-3_2 and Balsam-5 wells had been analyzied for both risk assessment and geomechanics modeling to properly understand the root causes and provide a recoemndations for future drilling operations in the same field and/or similar fields and Geoelogical age.Three liecened softwares had been considered in the study.The 1 st one was related to risk identification, meanwhile the 2 nd software was utilized to build the geomechanics modeling whereas the 3 rd software utilized to detect the maximum horizontal stress (SHMAX) from borehole image analysis.

Risk Identification
Daily drilling reports was utilized to build the drilling and geomechnical events excel sheet improved by (Pessoa, 2017)

Geomechanics Modeling
Wellbore stability is a function of how rock mechanically behaves under stress redistribution while drilling, rock may fail or yields according to rock strength and stress magnitude and orientation.The main components of a geomechanical model are shown in Fig. 3; three principal stresses, and Formation pressure (Pp) and the rock mechanical properties and rock strength (Hamid et al., 2018).A licened software had been utilized to build the Geomechanical model for three wells based on the available data, The overburden stress () is calculated through the integration of bulk density data whereas Pore pressure methods applied are based on Terzaghi's effective stress principle (1920s).Terzaghi's principle states pore pressure (Ppr.) as the difference between the overburden pressure and the effective stress.Effective stress is the amount of overburden pressure that is carried by the rock matrix.In other words, vertical stress minus matrix stress equals pore pressure.Another licened software used to detect the maximum horizontal stress (SHMAX) orientation from borehole images analysis.

Risk Analysis Approach
The risk analysis approach is a multi-discipline assessment based on geomechanical and geological model, subsurface knowledge of the area and operational experience.During the risk assessment the risks/hazards are identified for each borehole section, the potential root causes and effects are listed and the probability of occurrence and impact determined for each risk or hazard in Table 1.Once the risk analysis is completed, this knowledge can be used to improve the Drill the Well on Paper (DWOP) for future wells with the operator.These stages are explained below (Rangel et al., 2020).Poor cementing/wireline stuck

Results
Daily drilling reports (DDR's) had been analyzed using standard geomechanical and drilling events analyzer to define the type of risks experienced while drilling, meanwhile a geomechanical and wellbore stability models had been constructed for three wells to calculate all the stresses and rock mechanics properties to eventually recommend the mud weight window required to stabilize the formations while drilling.At the end a risk analysis approach built considering all drilling and geomechanics events indicating the root causes and possible solutions.

Drilling and Geomechanics events analysis -Balsam-2 Well & Sidetrack 1 & 2
Fig. 4. indicates a drilling challenges throughout drilling both 12 ¼" and 8 ½" holes for main hole and both sidetracks 1 & 2. The major challenges include tight spots and stuck pipe, whereas there were no recorded drilling challenges throughout drilling 6" hole in sidetrack-2.
In the main hole; FIT (Formation Integrity Test) performed on 12 ¼" hole at 1368 m and showed 13.50 ppg, the same test run on 8 ½" at 3113 m and showed 15.0 ppg.In sidetrack-2; FIT performed on 8 ½" hole at 3057 m and showed 15.0 ppg value, whereas FIT showed 13.50 ppg at 3479 m for 6" hole.

Drilling and Geomechanics events analysis -Balsam-3 Well & Sidetrack 1 & 2
Fig. 5. indicates a drilling challenges throughout drilling 12 ¼" hole for main hole and both sidetracks 1 & 2. The major challenges include tight spots, downhole losses and stuck pipe & pack off, whereas there were no recorded drilling challenges throughout drilling 8 1/2" hole in sidetrack-2.
12 ¼" main hole and sidetracks-1 & 2 drilled using silicate mud system with mud density ranges from 12.0 -12.90 ppg, 12.0 ppg and 9.80 -12.9 ppg, respectively, whereas 8 ½" for both sidetrack-2 drilled with KCl Glycol Polymer Mud at mud density range from 10.50-12.0ppg.12 ¼" holed drilled through both Kafr El Shiekh & Abu Madi formation that are consisted of mainly shale and sandstone, whereas 8 ½" hole drilled through Abu Madi and Qawasim Pay I formation that consisted of sandstone and shale intercalations.FIT (Formation Integrity Test) showed a value of 13.5 ppg in 12 ¼" hole at 1337 m, whereas FIT performed for 6" hole and showed 15.0 ppg at 2888 m.

Drilling and Geomechanics events analysis -Balsam-5 Well
Fig. 6. indicates a drilling challenges throughout drilling 12 ¼" hole for main hole.The major challenges include tight spots, downhole losses, whereas there were no a stuck pipe challenges recorded throughout drilling 8 1/2" hole.12 ¼" main hole drilled using KCl/silicate mud system with mud density ranges from 11.6 -12.0 ppg, whereas 8 ½" for main hole drilled with KCl/Glycol/Polymer Mud at mud density range from 11.50-12.20 ppg.12 ¼" holed drilled through both Kafr El Shiekh & Abu Madi formation that are consisted of mainly shale and sandstone, whereas 8 ½" hole drilled through Qawasim Pay I formation that consisted of sandstone and shale intercalations.FIT (Formation Integrity Test) performed for 8 ½" on Qawasim Pay I and showed a 14.0 ppg at 3209 m.

Geomechanics Modeling -Balsam-2-2 Sidetrack Well
A geomechanical model was built using data available data Fig. 7, where the overburden gradient (Sv) was calculated using density and pseudo-density data (calculated from acoustic using a calibrated Gardner equation for each lithology).
For the intervals where logs were not available, an exponential trend was used fitted to mud line at 2.1g/cm 3 and to actual density data at depth.Generally calculated overburden was very similar in all offset wells.Shale pore pressure was calculated using normal compaction trend line method.Eaton's method (Eaton, 1972) is used for resistivity and acoustic with exponents 0.6 and 1.5, respectively.Equivalent depth method was used for density.No great amount of overpressure was predicted in the shales.the sands pore pressure was calibrated to measured formation test (in Balsam-2 ST, 9.1ppg in QP1 (Qawasim I), 11.5ppg in QP2 (Qawasim II).

Calibrated Gardner
Rock mechanical properties are calculated from acoustic log using empirical equations for each lithology.These equations are calibrated in a way with actual drilling experiences, but no lab test data was available to get a more robust calibration to reduce uncertainties.
The minimum horizontal stress, Shmin (conservative estimate of the frac gradient) was calibrated estimated using an effective stress ratio method.The same ESR was used in all offset wells.
Failure features (breakouts and tensile features) observed on the image logs Fig. 8 that shows a general NW to SE SHmax azimuth.Variations in failure features orientations in the wells range from 97 deg to 142 deg.The average orientation was 121 deg.These variations could be due to localized rotations, but they may also be affected by the nature of the image log acquisition.
Maximum horizontal stress, (SHmax) is estimated by modelling wellbore failure observed in the image logs from offset wells.Uncertainty exists in the magnitude of SHmax.Drilling induced tensile fractures observed in the image logs which would show a higher SHmax resulting in a strike-slip stress regime, However, these features are not pervasive and may be the result of localized stress focusing on certain lithological boundaries and not representative of the overall stress in the wellbore.Fig. 9 indicates that Overburden is calculated by integrating the bulk density log over depth.Where density is affected by bad hole condition a pseudo-density calibrated using a modified Gardner's equation for each lithology is used.An exponential trend line is used where no logs available.Both the exponential trend and the Gardner equations are the same as developed for the study Area.
Shale pore pressure is calculated using normal compaction trend line method.In the sands pore pressure is calibrated to MDTs.Trendlines are the same as used in the previous offset study wells.
The same rock mechanical property equations as used for modelling the previous offset study wells are used for the Balsam-2 ST.

Geomechanics Modeling -Balsam-3-2 Sidetrack Well
In the image log, tensile regions are observed (~125 deg) which agree with the general stress orientation over the field.Due to the nature of the acquisition there is some uncertainty in this orientation.Orientation determined in nearby wells Balsam-1 and El Basant-1 ranged from ~111 to 132 deg.
No LOTs were available to confirm/update the least principal stress, Shmin.No features were observed in the image log to constrain the magnitude of SHmax further.The same effective stress ratios used in the previous study wells will also be used here.
Fig. 10 indicates that the Orientations of stress determined from image logs across the field show a NW-SE trend which agrees with data from the world stress map.Some variances in the orientation can be due to the nature of the FMI image log acquisition and lack of failure, or localized variation due to complexity of the faulting in the area.
Image logs from near vertical sections of the Balsam-3 ST2 do not provide any further drilling induced failure to constrain the magnitude of SHmax.The same effective stress ratios as determined in previous offsets is used.Note, tensile failure observed in Balsam-3 ST2 is minor and similar to that observed in previous offsets.Breakouts are anisotropic thus it is not fully due to shear stress alone and cannot provide further constraint.

Geomechanics Modeling -Balsam-5 Well
Fig. 11 shows the geomechanics model where the transitional to Normal faulting stress regime is modelled: SV  SHmax > Shmin The vertical stress was interpreted based on density data.If not available, density log is replaced by exponential trendlines and/or pseudo density profile computed from acoustic data.
Pore pressure modeled as hydrostatic up to Kafr El Sheikh top.In the reservoir sections, pore pressure is calibrated against available formation pressure estimates in Abu Madi & Qawasim, provided by the operator at~ 6380 psi.
FITs were provided for Balsam-5 to help calibrate Shmin.FITs only give a sign of lower bound for Shmin at 14.0 ppg.Image was not available for Balsam-5 to further constrain the maximum horizontal stress.ESR values of 0.65-0.72 & 1 are respectively used based on regional experience.

Discussion
Both Risk identifications and Geomechanics modeling for three studied wells indicate a lot of drilling challenges specially for 12 ¼" and 8 ½" holes compared with 6" hole.The challenges include (but not limited) tight spots, back-reaming, downhole losses, pack off and differential sticking throughout drilling Abu Madi and Qawasim Pay I & II Formation.12 ¼" hole sections experienced more tight spots and pack off as it has a lot of shaly sections, meanwhile 8 ½" hole experienced more downhole losses and differential sticking where has a lot of high permeable sandstone intervals .8 ½" section drilled with an extreme overbalance that also confirm the differential sticking mechanisms along with high formation permeability.
The highest uncertainties are from rock properties (UCS and Internal Friction), this is because no rock strength tests have been conducted on the available core samples, meaning that these properties are not calibrated and rely on log-derived equations.
A further petrophysical analysis is required to delineate the troublesome zones, calculate the porosity, permeability, and volume of shale & formation salinity.All those data would be utilized to customize drilling fluids additives and optimize wellbore strengthening and eventually enhances well design.Integrating risk identification, geomechanics analysis and petrophysics evaluation would close all the gaps in understanding mechanisms of subsurface challenges and deliver a completed solutions.

Conclusions
Basalm field is located at East Nile Delta, Egypt.Qawasim sandstone reservoir is the main source of gas production for El Wastani company.Qawasim Reservoir is classified into Pay I and Pay II based on reservoir characteristics.At the time of the study 8 wells had been drilled in the field, where a lot of drilling challenges had been experienced that resulted in sidetracking most of the original holes two times that cost the operator a lot of monies.Our study focuses on three wells mainly, where we got most of the data required to do a proper analysis.
Our study exhibits that there are three major challenges experienced while drilling phase of reservoir section such as tight spots while tripping, downhole losses, and differential sticking.Based on risk identification, assessment & geomechanics analysis; root causes of those three major challenges were related to invasion/thick filter cake over a high permeable zone due to excessive overbalanced drilling with lacking improper wellbore strengthening package of drilling fluids.the research.The authors extend the acknowledgement to cover both Baker Hughes and Schlumberger service providers for allowing us to use their premium software's for optimum calculations.
10th, 2012, to total depth equal 3315 mt in West El Manzala Concession.Basalm-2 drilled as development, deviated on 22, May 2015 to a total depth equal 3268 m in West El Manzala concession, whereas Basalm-3 drilling commenced on 01, June 2015 to a total depth at 3265 m as exploratory deviated pilot hole in Balsam Development lease, Balsam-4 drilling commenced on 23, February 2016 to total depth of 3957 m as development, horizontal well in Balsam Development Lease and eventually Balsam-5 drilling commenced on 23, April 2016 to total depth of 3575 m as development, deviated in Balsam development Lease.

Fig. 1 .
Fig.1.Location Map of Balsam Field-West El Manzala Concession (DanaGas, 2015) and licensed by Baker Hughes to delineate the drilling risks showen in Fig.2.The Daily Drilling Reports (DDR) analysis excel sheet represents time and mud type located on the X-axis whereas formation names, depth in meter and mud weight in ppg located on Y-Axis.FM represents the formation name and mud type indicates the drilling fluids type utilized to drill the Section.Color coding considered to indicate the riks type e.g.red circle indicates tight spots, sequare orange color indicates packoff, whereas triangle yellow color indicates stuck pipe.