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Results
Abstract The field study is in northern part of Kuwait targeting heavy oil formation, known to be shallow unconventional oil reservoir. It is heterogeneous shallow sandstone reservoir (500ft TVD) with low maturity oil, has low natural pressure, and poorly consolidated. Mud losses known to be the main risk of horizontal drilling in shallow heavy oil environment and the heterogeneous including continuity of the sand are also challenging for geo-steering team in order to place the well in the optimum position. Seismic is not available, however due to high offset well density a good correlation map has been produced. We are using formation tops from offset wells to delineate the continuity of the sand and trend of the structure dipping, we called it as shooting point method, which is assuming the trend of the structure from one offset well to another nearby offset well. The resistivity contrast will be expected to give us around 9 ft depth of detection (DOD) for our Azitrak resistivity tool based on Picasso plot. We made some scenarios for exiting the reservoir and it showed us some early warning 80ft to 180 ft prior to exit the reservoir. We use Autotrak, Azitrak dan Litotrak formation evaluation and density imaging tool to geo-steer and optimally place the wellbore inside 1B sandstone. The expectation of drilling the lateral was below 1000ft MD due to wellbore stability issue. From the correlation of available offset well it is clearly seen, there are two sand bodies in heavy oil target sand. The thickness is around 30-40 ft TVD and the structure was expected to be flat or a little bit dipping down. The well was landed in the middle of 1B, based on correlation of actual landing point log data to the nearest offset wells. Distance to bed boundary (D2B) showed local conductive layer from bottom since drilling the lateral section, which was not the response of base of 1B sand. So it was recommended to go down in stratigraphy in order to place the trajectory at the bottom part of 1B sand. In order to minimize wellbore stability issue along the lateral section, Bakerhughes recommended to maintain consistent faster ROP (80-100ft/hr) and effective hole cleaning. In the middle of lateral section of well B (1750ft MD) the well trajectory was inverted for the optimum production purposes to total depth (2250ft MD). Total lateral length achieved is 1116ft MD which covers 100% of the lateral length. Shooting point method in defining the rough structure trend from one well to another well was effectively applicative in the field, where current structure after drilling the lateral section is almost flat or slightly dipping down same as predicted before.
- North America (1.00)
- Asia > Middle East > Kuwait (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Ratqa Field > Lower Fars Formation (0.99)
Wellbore Strengthening in Narrow Margin Drilling
Benyeogor, Ogochukwu (1Shell Petroleum Development Company, Port Harcourt, Nigeria) | Awe, Sunday (1Shell Petroleum Development Company, Port Harcourt, Nigeria) | Amah, Obinna (1Shell Petroleum Development Company, Port Harcourt, Nigeria) | Ugochukwu, Oseme (1Shell Petroleum Development Company, Port Harcourt, Nigeria) | Erinle, Adeyemi (1Shell Petroleum Development Company, Port Harcourt, Nigeria) | Akinfolarin, Ayodele (1Shell Petroleum Development Company, Port Harcourt, Nigeria) | Oseme, Ugochukwu (1Shell Petroleum Development Company, Port Harcourt, Nigeria)
ABSTRACT Natural gas is one of the cleanest energy sources, its uses range from fueling power stations to cooking and heating. Global demand for natural gas is expected to rise in the coming years. Meeting these energy demands means drilling deeper exploration and development wells to access huge volumes of gas present under high pressure and high temperature (HPHT) conditions. Despite the attractiveness of the reward, managing the narrow drilling window between the reservoir pore pressure and the formation fracture gradient has remained a major source of cost escalation and non-productive time on HPHT projects. In order to improve the economics of HPHT projects, technologies like Managed Pressure Drilling and borehole strengthening have been used as a means of mitigating the risks associated with narrow margin drilling, thus enabling a paradigm shift from traditional casing seat selection methodology. In the Niger Delta, it is not uncommon to observe significant jumps in pore pressure values in proximate high pressure formations. The simplification of well designs and successful drilling operations are often challenged by the need to navigate through series of high pressured reservoirs in narrow margin windows. Compliance with process safety requirements requires selection of mud weight that is low enough to prevent mud loss and high enough to overbalance the reservoir pressure. Mud loss induced by formation fracture is often encountered in tight margin drilling, and when this happens, the focus shifts to strengthening the damaged wellbore using various techniques such as pumping chemical resins to seal off the loss zones. Various degrees of results have been achieved when borehole strengthening techniques are deployed with the objective of restoring wellbore integrity in both permeable and non-permeable formations. Successful deployments have resulted in achieving the well objectives safely and cost effectively. This paper details loss of wellbore integrity experienced on an HPHT well in the Niger delta and the wellbore strengthening strategy that was used to restore the strength in a non-permeable formation. It sheds light on how understanding the nature of the fracture, rock lithology as well as proper job execution can restore a damaged wellbore to its previous strengths. A Cost reduction approach to the execution of the strategy is also discussed.
Exploratory Drilling in Severely Ballooning Formation - Use of Best Drilling Practices and Real Time Monitoring for Low Cost Mitigation
Golwalkar, A. (Cairn India Ltd) | Lang, C. M. (Cairn India Ltd) | Doodraj, S. (Cairn India Ltd) | Singh, A. K. (Cairn India Ltd) | Manoranjan, K. (Cairn India Ltd) | Pandita, A. (Cairn India Ltd)
Abstract Wellbore ballooning (or wellbore breathing) is a pertinent drilling issue in exploration wells where the formation lithology, geo-mechanics, pore pressure and fracture pressure regime is not fully understood. This phenomenon is generally observed in formations with micro-fractures. While the pumps are on the ECD is just sufficient to open up the natural micro-fractures allowing the mud to enter the formation. As the pumps are switched off the dynamic pressure effect is lost and the static mud weight is insufficient to keep the fracture open, resulting in the mud lost in the formation to flow-back as the fracture closes. A flow back of mud is observed on the surface with pumps off, which can be misinterpreted as wellbore influx or kick. Misinterpreting a wellbore ballooning phenomenon as a well kick can lead to the application of standard well control procedure which can aggravate the problem and may have severe implications even to the extent of well failing to meet its objective and being prematurely abandoned. This paper presents case studies of two wells, viz. NJ North East-1 and Raag Deep Main-1, drilled by the operator in the same block. Severe ballooning was observed in the first well wherein delayed identification of the phenomenon resulted in high NPT and consequential cost impact. The lessons learnt from this experience were implemented in the second well with similar ballooning issues, along with close real-time well monitoring while drilling resulting in smooth drilling operation and successful achievement of objectives as per plan This paper also summarizes suitable in-field drilling practices to be adopted and implemented to mitigate wellbore ballooning, which can be a low-cost alternative to expensive technologies used to counter this phenomenon.
- Geology > Rock Type (0.89)
- Geology > Geological Subdiscipline > Geomechanics (0.39)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Raageshwari Deep Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Thumbli Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- (11 more...)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Pressure Management > Pressure effects in drilling (1.00)
- Well Drilling > Drilling Operations (1.00)
Abstract Mud weight optimization is a key driver in attaining optimum wellbore stability while drilling horizontal wells. This paper demonstrates the role of geomechanical knowledge prior to and while drilling to address wellbore stability related issues to help reduce drilling risk and non-productive time (NPT). To maximize gas production from a tight carbonate reservoir, horizontal drilling and multistage hydraulic fracturing methods have been adopted. For several wells, maintaining wellbore stability has been a challenge without prior geomechanical knowledge of the field resulting in undesired drilling events such as tight hole excessive reaming, stuck pipe, and difficulties while making trips. Even in wells with pre-drill geomechanical analysis for mud weight recommendations, uncertainty in the pore pressure due to depletion along the horizontal section of the wellbore, drilling with one recommended single mud weight (MW) posed great challenge to manage wellbore stability. In this paper, statistical analysis of data is used to investigate root causes of wellbore stability related issues for a number of horizontal wells drilled in the direction of the minimum horizontal stress. The analysis suggests that wells drilled with little understanding of geomechanical properties along the wellbore path encountered significant NPT's compared to those wells where understanding of rock mechanical behavior and in-situ stresses was utilized to make recommendations prior to drilling. In some cases it helped reduce NPT to less than 2% even in exploration wells. Among the successful wells, results from a case study describing the real-time (RT) geomechanics workflow was used to optimize MW enabling drilling the well to the planned target depth. The uncertainty related to pore pressure and intervals of high porosity which creates a significant risk of differential sticking were addressed by incorporating RT data and updating wellbore stability models and providing recommendation to the field operation. The paper demonstrates the role of geomechanics and its impact to drilling operations aimed to reduce operation cost and increase drilling efficiency by eliminating geomechanics-related wellbore stability problems.
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (5 more...)
Abstract Conductor jetting has been the preferred installation method for deepwater drilling. This type of installation depends on the skin friction between the conductor and the formation, making axial load capacity the critical success factor. Failure of axial load resistance causes well subsidence, incurring high cost in a deepwater environment. In principle, a longer conductor length gives higher axial capacity. The PSC Company has drilled deepwater wells in East Malaysia and plans to drill more wells in the future. The conductor was designed using the same parameters as the nearby fields and the historical data. In addition, third-party companies normally perform conductor analyses based on the Gulf of Mexico soil set-up rate, which is not similar to East Malaysia. These practices have inadequate theoretical support and could lead to failure. The paper objective is to analyse the conductor length requirement for East Malaysia with The PSC Company's planned conductor. The analysis includes the conductor length requirements for different well parameters. The soil profile was derived from the nearby field soil-boring data and previous well parameters to obtain the soil set-up curve. The soil profile was matched with various parameters to analyse the required conductor length. The result describes the significant effect of conductor and jetting bottom hole assembly weight. Higher weight gives more weight on bit, providing high immediate capacity and requiring a shorter conductor. In addition, setting long 20" casing imposes a higher load that requires a longer conductor. However, PAD mud weight and duration before land weight on the conductor do not provide a significant effect. Moreover, other conductor specifications that may be run in the future were analysed, showing the same tendency, where a heavier conductor requires a longer conductor. This analytical method can be recalibrated for other conductor configurations in the future. The information contained herein is provided with the understanding that the COMPANY makes no warranties, either expressed or implied, concerning the accuracy, completeness, reliability, or suitability of the information.
- Asia > Malaysia (1.00)
- North America > United States > Texas (0.28)
Abstract Several concerns arise at the field development planning stage which may be only answered by geomechanical studies, such as wellbore stability analyses, sanding risk assessments, and studies of compaction and subsidence during the life of the field. These issues can be very important in large projects in deep-water environments. A comprehensive geomechanical study was conducted for an offshore deep-water gas field in Southeast Asia as part of the field development planning. The study covered a wide range of geomechanical studies from drilling to production stages for the entire life of the field. The geomechanical model was built based on the available logs and data from the exploration and appraisal wells drilled in the field. The model was then used for several geomechanical applications; a) wellbore and fault stability analysis to investigate the effect of the well trajectories on mud weight recommendations and casing design, b) sand production prediction analysis to study the risk of sanding for different completion scenarios, and c) compaction and subsidence analysis to study the impact of depletion on the platform and subsurface designs. A wellbore stability analysis was conducted to investigate the effect of wellbore trajectory on the safe mud weight window. The analysis suggested that the collapse pressure for any well in the field is dependent on the deviation of wells rather than their azimuths. The impact of the stability of the natural fractures and faults on the upper bound of the safe mud weight window was investigated in detail. The analysis showed that the mud weight required to reactivate the natural fracture and fault intersecting the wells is above the upper bound of the safe mud weight window defined by the wellbore stability analysis. The sand production prediction analysis showed that sanding is expected from the early stages of production for both open-hole and cased and perforated completions. The analysis suggested that selective and oriented perforations may only delay or reduce the risk of sanding and cannot eliminate it entirely. The compaction analysis showed that the maximum compaction is less than 1% for all reservoirs. This is significantly lower than the general criteria of 3% – 5% which may cause problems for casing and completion systems. Moreover, the maximum total calculated subsidence at the seabed is expected to be below the engineering design limits. All the methodologies and approaches used to conduct the above mentioned geomechanical analyses, and interpretation of the results are thoroughly explained in this paper. This study highlights the importance of the geomechanical studies for decision making in deep-water field development planning.
- Asia (0.85)
- North America > United States (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.32)
Integrating Wireline Measurements to Provide Geomechanical Solutions: A Case Study for Optimizing Drilling by Improving Wellbore Stability in a Complex and Tectonically Active Region
Roy, Sunit (Oil and Natural Gas Corporation Ltd.) | Roy, G. K. S (Oil and Natural Gas Corporation Ltd.) | Chauhan, R. S. (Oil and Natural Gas Corporation Ltd.) | Bahuguna, Somesh (Schlumberger Asia Services Ltd.) | Zacharia, Joseph (Schlumberger Asia Services Ltd.) | Chatterjee, Chandreyi (Schlumberger Asia Services Ltd.) | Basu, Jayanta (Schlumberger Asia Services Ltd.) | Bhuyan, Priyanuz (Schlumberger Asia Services Ltd.) | Talreja, Rahul (Schlumberger Asia Services Ltd.)
Abstract In recent years, exploration in northeast India has focused mainly in the area south of the Naga fault. This area is tectonically active with complex folding and faulting. Target formations are in excess of 3,000m through these complex structures. ONGC has drilled several wells in the Tripura region of northeast India. Although results were encouraging, the main challenges faced during drilling were various well control and instability events: kicks, tight hole, stuck pipe, lost in hole, etc. The causes of this instability were difficult to isolate. Experience from past wells also indicated the existence of overpressure in the Middle Bhuban Formation, which could not be accurately predicted by surface seismic data. Hence, drilling through these highly stressed and overpressured formations led to excessive NPT and cost. In addition, severe hole enlargement and rugosity through eventual reservoir sections resulted in poor logging conditions and uncertain reservoir evaluation. As a result, access and interpretation of the reservoirs, to prove and produce reserves, is a major challenge in this region. In this paper, two case studies are presented to show how a geomechanics-based approach has significantly improved drilling rates by reducing the drilling-related problems. New wells were drilled within 40% of the planned number of days. Better hole conditions not only improved drilling performance but also led to huge improvements in reservoir evaluation and the identification of unloading mechanisms, probably caused by uplift due to thrusting, in the Middle Bhuban Formation. Integrated study provided valuable information about overpressure and stresses acting in this field/structure for future drilling.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > India Government (0.36)
Three-Dimensional Full-Field and Pad Geomechanics Modeling Assists Effective Shale Gas Field Development, Sichuan Basin, China
Xing, Liang (PetroChina) | Chenggang, Xian (Schlumberger) | Honglin, Shu (PetroChina) | Xin, Chen (Schlumberger) | Jiehui, Zhang (PetroChina) | Heng, Wen (Schlumberger) | Gaocheng, Wang (PetroChina) | Lizhi, Wang (Schlumberger) | Haixiao, Guo (Schlumberger) | Chunduan, Zhao (Schlumberger) | Fang, Luo (Schlumberger) | Kaibin, Qiu (Schlumberger)
Abstract A shale gas field at the southern edge of the Sichuan basin, China, started its oilfield development plan (ODP) in early 2014. The first wells drilled in this field and its adjacent blocks experienced significant challenges, such as severe mud losses, stuck tools, losses in the hole, high treating pressure, and unexpected screenout. Because it is vital to have accurate understanding of geomechanics and its roles at various scales, three-dimensional (3D) full-field and pad geomechanics models were developed for achieving both efficiency and effectiveness during the ODP. The work is based on high-resolution structural, geological, reservoir property, and multiscale natural fracture models. An extensive characterization of mechanical properties was conducted by the evaluation of cores, well logs, and seismic data. A systematic approach was implemented to build a 3D pore pressure model of the field. Finally, an advanced finite element simulator was used to compute 3D stress distribution, which fully owns all features and local changes of structural, geological, mechanical, and reservoir properties, and multiscale natural fracture models. The large model (80×80-m cell) covers the full field, and the pad model (20×20-m cell) covers a 15- to 20-km area. All have 0.5-m vertical resolution of the targeted sweet section to capture vertical heterogeneities measured from logs. Large-scale parallel computing technology was used to perform such massive geomechanical modeling. The models were calibrated or constrained by all available data such as mud logs, cores, borehole images, drilling data, prefracturing injection tests, hydraulic fracturing responses, microseismic events, and flowback data. All models were updated continuously when new data became available. The computed stress models match the highly compressive background and current understanding of the dominant tectonic movements of the Sichuan basin. They are sufficient to reveal orientations, magnitudes, anisotropies, and heterogeneities of in-situ stresses. Large variations of in-situ stresses can be quantified among pads and wells and along laterals. Such variations correspond to or align with changes in texture and composition at various scales, such as faults and complex multiscale natural fractures. The full-field model was used to optimize pad and well locations and well trajectories and assess geological integrity, resources in place, and instability of natural fractures. The high-resolution pad models were used for near-wellbore stability analysis, real-time drilling management, engineering hydraulic fracturing design and monitoring, and integrated post-fracturing analysis. The implemented approach was proven to be effectively integrated into the progress of drilling and completion. This is the first time such 3D geomechanics models have been built for China's shale gas development. The knowledge and experience gathered can certainly benefit other similar projects.
- Asia > China > Sichuan Province (1.00)
- North America > United States > Texas (0.68)
- Phanerozoic > Paleozoic (0.94)
- Phanerozoic > Mesozoic > Triassic (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.69)
Application of Coil Tubing in High Density Mud in Deep HPHT Well
Al-Muhailan, Mohannad (Kuwait Oil Company) | Patil, Dipak (Kuwait Oil Company) | Aljarki, J. (Kuwait Oil Company) | Mahesh, V. S. (Kuwait Oil Company) | Shehab, A. (Kuwait Oil Company) | Al-Azmi, Salah (Kuwait Oil Company) | Alshammari, Faisal (Baker Hughes) | Al-Jaber, Mohammed (Baker Hughes) | Ababou, Mounir (Baker Hughes)
Abstract This paper highlights the design, planning, challenges, operational complications and successful execution of coil tubing application in active deep well in West Kuwait. The aim of coil tubing job is to clear the pipe from inside to recover the stuck pipe to eliminate the sidetrack in highly pressurized complicated Salt/Anhydrite sequence. In one of the West Kuwait wells, during drilling the well got a kick with high gain rate. During shutting in and at starting of killing the well, it was observed that the pipe & annulus were plugged. Pipe puncture job was carried out & the well was killed off bottom with 19.7 ppg mud. Throughout running in hole with the free point locator tool prior to back off job, the held up was observed at 12,490 ft i.e. 1,300 ft above the bit. It was then selected to clean inside drill pipe to avoid sidetracking. The well conditions presented challenges to the design and operation of coil tubing in this well. Challenging factors included: Use of high weight and yield strength, 15 ksi coil tubing, high mud density of 19.7 ppg, high pumping pressures, deep well, ID restriction 3 ½ in DP with 2 in ID, active well, deviated well of around 57 degrees. The coil tubing job design was critical for success of the operation. It included selection and analysis of coil tubing material, size, wall thickness; managing potential coil tubing burst and collapse pressures, calculation of coil tubing stretch, circulation pressure with high density mud, coil tubing force analysis, and wellbore solids removal with very minimum clearance & minimum pumping rate. Initial simulations with 1.5 in coil tubing showed that circulation pressures would go above the 15 ksi rating. It was then decided to switch to high pressure 1.75 in coil tubing with which simulation showed that pressures at the rotating joint would be at 8,000 psi, using a jetting nozzle. While lowering with jetting nozzle, held up was observed at overshot due to the deviation. After changing jetting nozzle with the 1 11/16 in kick off tool, the coil tubing was able to pass through the gelled mud with circulation. To keep under check, high circulating pressure with aid of hydraulics analysis, related to dynamic circulation rate to 0.2 bpm at 7,500 psi & static rate to 0.35 bpm with 8,500 psi. Resulting in successfully clearing the drill pipe from inside to 12,974 ft, below the observed settling of hard barite. Coil Tubing intervention with the restricted pipe diameter and heavy mud at high inclination well using a kick off tool was done for the first time in Kuwait. It achieved the purpose of cleaning the pipe to definite depth enabling back off operation below the jar & enhanced the chance of pipe recovery.
- Asia > Middle East > Kuwait (0.75)
- North America > United States > Texas > Harris County > Houston (0.28)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Abstract Formation Pressure While Drilling (FPWD) is regularly used in exploration and appraisal environments for drilling optimization purposes. The service is integrated into pore pressure prediction workflow and due to the uncertainty in the pore pressure, interpretation of the pretest acquired can sometimes be challenging. This is particularly relevant when the measured pressure is in a near or underbalance condition. Near balance wellbore pressure is defined as formation pressure being marginally less than wellbore pressure. Underbalance wellbore pressure is when the formation pressure is equal or higher to the wellbore pressure. During wireline formation pressure testing the static logging environment contrasts with the dynamic drilling environment with respect to wellbore pressure, the latter can be affected by mud circulation amongst other parameters. An adequately overbalance condition with mud flow-on can change to underbalance condition when flow is static or changes are made to mud rheology. In exploration and appraisal drilling where pore pressure uncertainty is at its highest, the wellbore conditions can change from planned overbalance to an undesirable underbalance scenario if an unanticipated high pressure zone is encountered. Such a scenario may result in a well control situation. Measuring formation pressure while drilling in near or underbalance situations poses challenges to the way formation pressure is measured. If the flowline pressure reads very close to, or is identical to wellbore pressure and is combined with limited data transmission rates then interpretation is difficult. The flowline pressure signature may look similar to a no seal or leaky seal pretest. Proper differentiation of the valid formation pressure and detecting a faulty seal are paramount to an accurate interpretation. Correct identification of these near/underbalance pretests is key to applying the right decision process and/or risk mitigation measures such as adjusting mud weight, drilling parameters or even casing depth. Analysis is carried out on a large number of FPWD pretests. A workflow is devised to successfully analyze and diagnose in real-time, pretests acquired in near/underbalance conditions. This highlights different subjective factors that affect the formation pressure measurement in both scenarios and its sensitivity. A safe procedure is described to eliminate the factors which create uncertainty, and layout steps to prove the validity of the formation pressure measurement made in near/underbalance conditions in real-time. This workflow has been successfully implemented for FPWD services in the Gulf of Mexico and the results are used as examples in this paper to illustrate the concept. This study enables understanding of the variables involved in interpretation of a near/underbalance pretest while the workflow assists in providing a systematic approach to diagnose the condition. The goal being proper mitigation of drilling events to avoid non-productive-time or an HSE event.