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Collaborating Authors
Well Drilling
Machine Learning Techniques for Real-Time Prediction of Essential Rock Properties Whilst Drilling
Amadi, K. W. (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait) | Alsaba, M. T (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait) | Iyalla, I. (School of Engineering, Gordon University, Aberdeen, United Kingdom) | Prabhu, R. (School of Engineering, Gordon University, Aberdeen, United Kingdom) | Elgaddafi, R. M. (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait)
Abstract Wellbore instability is the most significant incident during the drilling of production sections of most wells. Common problems such as wellbore collapse, tight hole, mechanical sticking, cause major delays in drilling time due to extended reaming and sidetracking in worst-case scenario. Geomechanical property of rock such as Unconfined Compressive Strength (UCS) affects wellbore stability, drilling performance and formation in-situ stresses estimation. Conventional methods used to estimate UCS requires either laboratory experiments or derived from sonic logs and the main drawbacks of these methods are the data and samples availability, high costs and time This paper presents an alternative technique of utilizing real-time drilling parameters and machine learning (ML) algorithm in the prediction of UCS thereby enabling timely drilling decisions. ML algorithm enables a system to learn complex pattern from the dataset during the training (learning) phase without any specified mathematical model and afterwards the trained model can predict through a model input. In this work, five ML models were used to predict UCS using offset well data from an already drilled wells. The models include; artificial neural network (ANN), CatBoost (CB), Extra Tree (ET), Random Forest (RF) and Support Vector Machine (SVM). The ML models were first trained with 1150 data points using a 70:30 percentage ratio for training and testing the model respectively. After that, 560 datapoints from a different well were used to validate the developed model. The real-time drilling parameters required included weight on bit, penetration rate, rotary speed, and torque. The analysis result revealed good match between the actual and predicted (UCS) with correlation coefficients for training and testing dataset; 0.970 and 0.70 and 0.85 and 0.77 for CatBoost and ANN respectively. The main added value of this approach is that these drilling parameters are readily available in real-time and timely drilling decisions can be modified to improve the drilling performance.
- Asia > Middle East (0.29)
- Africa > Nigeria (0.28)
- Europe > United Kingdom (0.28)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Offline Production Tree Installation: Key Decisions, Value Drivers and Lessons Learnt
Elendu, C. (Chevron Nigeria Limited, Lagos, Lagos, Nigeria) | Bajomo, V. M. (Chevron Nigeria Limited, Lagos, Lagos, Nigeria) | Enuneku, N. (Chevron Nigeria Limited, Lagos, Lagos, Nigeria) | Nwamara, N. J. (Chevron Nigeria Limited, Lagos, Lagos, Nigeria)
Abstract After successfully drilling and completing 40 wells with 5000 psi rated production trees in the swamp operation within a 5-year campaign the diverter deck on the Swamp Rig barge never posed a challenge until 6650 psi production tree had to be installed on two non-associated gas wells. The Field Development Plan (FDP) was approved in 2013 and it contained a 2-well (NAG-1A and NAG-2A) development plan for the target reservoirs with estimated recovery of 213 BCF of rich gas and 4.6 MMSTB of pool condensate at initial production rates of 35 MMSCFD and 1,380 BCPD each for both wells. Gas production from these wells will bulk flow to the NAG separator located at the Production Flow Station where the pool condensate will be separated from it. The rich gas will subsequently be transported to the gas plant onshore bypass for supply to the domestic market through the ELPS. NAG-1A and NAG-2A wells are part of the Non-Associated Gas (NAG) development and were completed as single string deviated gas producers with HRWP completions to meet target production rates and reserve recovery. After successfully drilling and completing the NAG-1A well, it was later discovered that the diverter deck of the rig was going to impact the 6650 psi production tree while moving the rig onto the NAG-2A well slot on the same jacket. This paper sets out to give an overview of the planning, risks assessment and execution for using a crane barge to successfully install two 6650 psi production trees on two NAG wells incidents free, after the drilling rig departed location due to the diverter deck limitation. Lessons learned and best practices were captured as well as the resultant cost savings from using the crane barge instead of the rig to install the production trees on the two NAG wells. The total number of days to complete the offline XMT installation using a crane barge was 5 days for both wells while working daylight hours only. This resulted in a cost savings of 154,200 USD per well.
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
- (6 more...)
Dimensionless Pressures and their Derivatives for a Vertical Well Completed within a Pair of Inclined Constant-Pressure Boundaries
Ojukwu, I. N. (Department of Petroleum Engineering, University of Benin, Benin-City, Edo State, Nigeria) | Adewole, E. S. (Department of Petroleum Engineering, University of Benin, Benin-City, Edo State, Nigeria) | Taiwo, O. A. (Department of Petroleum Engineering, University of Benin, Benin-City, Edo State, Nigeria)
Abstract Dimensionless pressure and their derivatives assist tremendously in understanding the reservoir boundary types, efficient well design, completion and production scheduling for optimum recovery from the reservoir. For a reservoir boundary as inimical as constant-pressure to oil or gas production, the need to adequately anticipate its presence and approach pattern towards the wellbore cannot be overemphasized. In this paper, dimensionless pressures and their derivatives are provided for a vertical well completed within a pair of inclined constant-pressure boundary (CPB) support. The angle of inclination of the constant-pressure boundaries is varied between 0 and 360 degrees. Hence, a generalized dimensionless pressure and derivatives expressions are derived by superposition of dimensionless pressures of all image wells on one object well. Therefore, distances of every individual well from the object well and the sign of every image, taken through a counterclockwise direction from the object well, are major inputs into the dimensionless pressures and dimensionless pressure derivatives derived. Only the object wellbore skin but not its storage is considered. The solutions are plotted as type curves. Results show dependence of both dimensionless pressure and dimensionless derivatives on angle of inclination of the constant-pressure boundaries. The dimensionless pressures exhibit a unique gradient at late dimensionless times. There is a collapse of the derivatives to zero at late dimensionless times. The rapidity of the collapse depends on object well distance from the boundaries and the angle of inclination of the boundaries. Wells completed farther away from the CPBs exhibit unperturbed production for longer periods than nearer wells.
Modified Solvent-Based Mud Acid Stimulation of Condensate Gas Reservoirs: Case Study of UUU Cluster in West Niger Delta
Osode, Peter (ND Western Limited) | Soro, Augustine (NNPC Exploration and Production Ltd) | Iyama, Andy (ND Western Ltd) | Otiede, David (NNPC Exploration and Production Ltd) | Olawunmi, Oduyemi (NNPC Exploration and Production Ltd) | Nwadiogbu, Lawrence (ND Western Ltd)
Abstract Matrix acid stimulation has been successfully applied to remove formation damage in the high-permeability Niger Delta sandstone oil and gas reservoirs since the mid-eighties. The predominant acid treatment fluid of choice is expectedly the regular mud acid (RMA) – hydrochloric acid and hydrofluoric acid (HCl:HF combination acid). Fluid formulation is however challenging for gas wells due condensate banking and water block development in the near-wellbore area at pressures below dew point pressure. Candidate wells were identified for stimulation after well test data analysis and production performance evaluation. This paper focuses on selection and application of a modified solvent-based RMA to remove drilling and completion fluid-induced formation damage in addition to production-related damage in high-rate, gas-condensate wells in a cluster of western Niger Delta fields. A low-strength alcoholic mud acid was selected primarily based on bottomhole temperature (< 220 °F), formation mineralogy – over 70% quartz with low clay content (< 5%) for the high-permeability hydrocarbon formations. The alcohol-based solvent – methanol was included in all stage treatment fluids (preflush, main treatment and overflush) for condensate bank removal and improved well production performance. Treatment fluid injection and soak treatment was applied at minimum threshold of 100 gallons per foot across the perforations using coil tubing. The results indicated improved well-inflow performance for the old gas-condensate compared to the newly completed well after adequate clean up. Average production gain realised in the aged wells was over 50%. This paper has confirmed the applicability of this modified RMA for near-wellbore formation damage removal without increasing the producing water gas ratio (WGR) in gas wells.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Formation Damage (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Well Completion > Acidizing (1.00)
- (5 more...)
Bonga Deepwater Project Mid-Life Abandonment Campaign – A Success Story
Ojeh-Oziegbe, Osehojie (Shell Nigeria Exploration and Production Company, Lagos State, Nigeria) | Okosun, Augustine (Shell Nigeria Exploration and Production Company, Lagos State, Nigeria) | Adubi, Oladokun (Shell Nigeria Exploration and Production Company, Lagos State, Nigeria) | Ugoh, Oluwatobi (Shell Nigeria Exploration and Production Company, Lagos State, Nigeria) | Ezenwanne, Elesie (Shell Nigeria Exploration and Production Company, Lagos State, Nigeria) | Jenakumo, Timi (Shell Nigeria Exploration and Production Company, Lagos State, Nigeria)
Abstract When oil and gas wells have been produced to the end of useful life, when the cost of production relative to the value derived converge to a point when producing the well is no longer profitable, the wells are decommissioned. Oil and gas well decommissioning and restoration refers to the process of permanently sealing and abandoning oil and gas producing reservoirs within a wellbore that are no longer productive or economical to operate, in a way that ensures safety and environmental protection in accordance with industry and local regulatory standards and requirements. As part of this philosophy, The project strategy was to decommission and abandon depleted wells as they reach their end of useful life in accordance with Shell PLC guidelines and local regulation as specified in Environmental Guidelines and Standards for the Petroleum Industry In Nigeria (EGASPIN). The field's midlife abandonment project was a first in deep water environment in Nigeria, developed and executed to permanently abandon selected wells that have reached their end of useful life by permanently isolating the reservoirs zones that are capable of flow and restoring caprock. This was achieved by recovering the completion, production and intermediate casing strings to expose the reservoirs traversed by the wellbore, then restoring the caprock using cement plugs which were set to create a rock-to-rock isolation of all zones with flow potential within the primary wellbore. The objective was to prevent crossflow between reservoir zones, isolate the reservoirs from the environment and marine life while safeguarding all subsea infrastructure from damage arising from the well abandonment operations. In total, thirteen wells with varying degrees of complexity were successfully decommissioned and restored without incidents or accidents. The fourteenth well had to be re-suspended due to multiple complex challenges which emerged during the abandonment campaign. The well needed to be replanned, ensuring the required equipment to execute the emerging challenges were available. As with every new project, several challenges were encountered, and new ideas were developed. These ideas include achieving better well integrity coupled with improved tubing and casing recovery practices and optimized cement plug placement will be a foundation for future deep water well abandonment in Nigeria specifically and the industry at large. The learnings from the project were adopted to generate a Standard Operating Procedure (SOP) for deep water well abandonment. These SOPs and all other learnings and best practices that led to the success of the mid-life abandonment campaign will be adopted in executing the end of field life abandonment for the project and will be shared on this paper.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Africa Government > Nigeria Government (0.46)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Production and Well Operations > Well Decommissioning (1.00)
- Health, Safety, Environment & Sustainability (1.00)
- (3 more...)
A Quantitative Analysis of the Impact of Well and Reservoir Parameters on Pseudo-Skin Due to Partial Penetration
Egbe, E. P. (CypherCrescent Nigeria Limited, Port Harcourt, Rivers State, Nigeria) | Hart, A. F. (CypherCrescent Nigeria Limited, Port Harcourt, Rivers State, Nigeria) | Omobolanle, O. C. (CypherCrescent Nigeria Limited, Port Harcourt, Rivers State, Nigeria / Department of Petroleum Engineering, World Bank Africa Centre of Excellence in Oilfield Chemicals Research, University of Port Harcourt, Rivers State, Nigeria)
Abstract Pseudo-skin factor due to partial penetration (Spp) is a crucial parameter when evaluating oilwell deliverability. It creates an additional pressure drop at the near-wellbore region with inimical impact on well productivity. Conventionally, a fraction of the reservoir thickness is targeted for perforation to maximize production and reservoir drive thereby increasing Spp. This paper investigates the impact of changes to pseudo-skin’s intrinsic parameters on its behavior. A software application (SENDI 6.0) was developed to automate the calculation and sensitize on the parameters. The results were subsequently regressed and analyzed to monitor the fractional contribution and impact of each parameter. The results of the investigation revealed that in comparison to other key parameters, penetration ratio is the largest contributor to Spp, accounting for about 37% of the pseudo-skin factor.
- Africa > Nigeria (1.00)
- North America > United States > Texas (0.28)
- North America > United States > California (0.28)
- North America > United States > Louisiana > Laplace Field (0.89)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 522 > Na Kika Project > Fourier Field (0.89)
- Well Drilling (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Pressures and Pressure Derivatives of Vertical and Horizontal Wells Located Within Intersecting Sealing Fault and Constant Pressure Boundary
Ojah, M. G. (Department of Petroleum Engineering, University of Benin, Benin City, Edo State, Nigeria) | Adewole, E. S. (Department of Petroleum Engineering, University of Benin, Benin City, Edo State, Nigeria) | Emumena, E. (Department of Petroleum Engineering, University of Benin, Benin City, Edo State, Nigeria)
Abstract The optimization of the performance of oil and gas wells (whether vertical or directional) as well as well location from external reservoir boundaries or faults has been a major concern of the reservoir engineer over the years. This work presents an accurate method for evaluating the performance of both the vertical and horizontal wells each located within an intersecting sealing/no-flow boundary and a constant-pressure boundary. The main aim of this study was to investigate the transient pressure behaviour of a vertical well as well as a horizontal well located within an intersecting sealing fault and a constant pressure boundary. The methods employed in computing the dimensionless pressures and dimensionless pressure derivatives for both well types include the method of images and principle of superposition. The computations were also made using Microsoft Excel, Python and MATLAB software. The results obtained show that for the selected parameters; 1) the models give accurate estimation of distances between active and image wells, PD and PD’, 2) at 30 hours of production, both wells completely overcome the effects of the boundaries at 2000 ft. equidistant to faults, 3) for the infinite-acting reservoir, a characteristic values of PD’ for the vertical and horizontal wells are 0.5 and 0.2 respectively, 4) for both well types, the effect of the upper boundary is greatly felt between distances of 5.00ft. and 10.00 ft., and beyond this region, the effect of the lower boundary becomes gradually felt and then, greatly felt beyond 15.00 ft. The relationship between the pressures and unequal faults distances has no maximum or minimum points, 5) the point with the least effect of either or both boundaries as well as longest transient period is point 3 (equal distance of 15.00 ft. from both boundaries). This is the point of optimal productivity, 6) for a given distance, both PD and PD’ decrease as horizontal well length L increases, 7) for all the cases considered and dimensionless time tD, both PD and PD’ decrease with increasing horizontal well length. The longer the well length, the lower the drawdown required to give same effects, as would shorter lengths, on the well performance at a given time of production thereby prolonging production over time, and 8) for a given distance, the horizontal well length has no impact on the flow periods. The type curves can be used for matching of actual pressure drawdown data and determining the drainage area and relative well location with respect to physical boundaries. Worthy of future research are similar works on; 1) anisotropic reservoir, 2) larger values of faults distances, and 3) angles other than basic angles.
Investigation of the Effects of Well Length Tapering on a Horizontal Well Performance in a Laterally Infinite Reservoir
Ukpong, P. O. (Department of Petroleum Engineering, University of Benin, Benin-City, Edo State, Nigeria) | Adewole, E. S. (Department of Petroleum Engineering, University of Benin, Benin-City, Edo State, Nigeria)
Abstract The amount of oil producible from a horizontal well can easily be reduced if the reservoir has external boundaries which are capable of attenuating further pressure transient propagation through the reservoir. Although several operational measures, such as well stimulation, well re-entry, can be implemented to further boost well production, wellbore length modification by tapering is investigated in this paper. The investigation involves development of a mathematical model for evaluating well performance up to first linear flow period for a tapered horizontal well in an anisotropic reservoir of finite reservoir thickness. Dimensionless radius in the flow model for dimensionless pressure of a horizontal well in a laterally infinite reservoir during linear flow is tapered. The effects of the tapered radius on unsteady state dimensionless wellbore pressure were studied for a hypothetical anisotropic reservoir. Both infinite conductivity and uniform flux cases are considered. The effects of near wellbore problems such as wellbore skin and storage are not considered. Results obtained shows that dimensionless pressure increases as dimensionless time increases and the time at which initial radial flow starts, persists further than completions that are not tapered. Furthermore, tapering delays time at which linear flow starts. Two scenarios were observed for well performance with respect to well length. In the first case, well productivity decreases as the length of the tapered string increases for a particular dimensionless time, while second case shows that performance increases when both dimensionless length and time increases. Reservoir, wellbore, and fluid properties are also found to affect well productivity no matter the number of tapered strings used during well completion. For example, as reservoir pay thickness increases, well productivity also slightly increases. Also, the influence of infinite conductivity and uniform completion is not felt strongly on well productivity whether the lengths are tapered or not. Study shows (1) prolonged infinite acting flow period compared to single tubing completion. This means that time to reach reservoir external boundary is increased with tapered completion than single tubing completion. (2) there is improved production rate compared to single tubing completion. This means that more oil is recovered per unit time for tapered completion. (3) tapered completion requires less frequent stimulation since damage is spread over a larger area instead of concentrating on only a single tubing with same diameter across the pay zone. (4) Mechanical damage is mitigated since larger tubing penetrates the pay zone. Reservoir and well completion engineers are now encouraged to employ tapered completions in horizontal wells for improved well production especially if the reservoir has external boundaries that are inimical to well productivity.
- North America > United States (1.00)
- Africa > Nigeria (0.69)
Analysis of Drilling Fluid Losses, Mitigation and Recovery while Transiting from Depleted to Overpressured Zones
Nwamaioha, Chibuzo Ogbonna (Shell Petroleum Development Company, Port Harcourt, Nigeria) | Tichelaar, Bart William (Shell Petroleum Development Company, Port Harcourt, Nigeria) | Anyaegbu, Onyeka Samuel (Shell Petroleum Development Company, Port Harcourt, Nigeria)
Abstract Identification of the extent of potential drilling challenges that could be encountered while transitioning from depleted or normally pressured zones to overpressured zones has never been straightforward. Front-End Engineering activities such as geological evaluation/modelling, drilling fluid (mud) designs, casing shoe setting depth selection criteria (formation isolation intervals), etc. comprise the minimum design inputs required to ensure safe and cost-efficient drilling through steep pressure ramps. However, these have not resulted in guaranteed success while drilling, as was seen in several wells studied in the same field. This paper discusses the case of an overpressured well in the Niger Delta where severe mud losses of over 120bbls/hr were encountered while drilling through an overpressured inter-reservoir shale below a depleted sand. Several attempts to cure the losses and strengthen the wellbore yielded varying degrees of success especially when measured against time in static and dynamic conditions. Further analysis of the petrophysical data indicated that the upper part of the inter-reservoir shale, just beneath the depleted zone, sits in a near-hydrostatic pressure regime with lower fracture gradient while the lower part of that shale layer is significantly overpressured with, consequently, higher fracture gradient. Petrophysical data, pore pressure prediction models and wellbore integrity considerations are integrated in a novel way to yield far-reaching insights into the impact of inter-reservoir shales on well design. This, together with loss circulation treatment options, is determined to result in improved characterization of hole stability risks and overall drillability of the well.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- (2 more...)
Bit Balling: Causes, Effects and Mitigation Using Bunmi-01 Well in Niger Delta as a Case Study
Kehinde, Sodiq Adejuwon (NNPC Exploration and Production Limited) | Ajayi, Olawale I. (Nigerian Petroleum Development Company Limited) | Akpan, Unwono (NNPC Exploration and Production Limited) | Odesa, David E. (Nigerian National Petroleum Corporation)
Abstract Drilling operations is typically characterized by various operational challenges ranging from surface to subsurface issues. The most prevalent subsurface drilling problems include pipe sticking, lost circulation, borehole instability, bit balling, hole cleaning etc. This paper aims to analyse the causes and effects of bit balling and the mitigation strategies that can be employed in the well planning and drilling phase using Bunmi-01 well in Niger Delta as a case study. Analysis of drilling data gathered from Bunmi-01 well shows that the bit balling is more prominent at depths within the range of 3,000ft – 6,800ft, mostly in the top-hole section (17½") of the well. In the well of interest, the bit balling phenomenon was characterized by a significant drop in average ROP from 78.8ft/hr to 1.5ft/hr (with instantaneous ROP as low as 1ft/hr) and increase in standpipe pressure from 1,200psi to 1,350 psi. Mud logging data also indicated a transition in lithology from predominantly sand (Sand: 70%, Clay: 30%) to predominantly clay (Sand: 20%, Clay: 80%). A total rig time of about 16.5 hrs (NPT) was lost in tripping out of hole, breaking up and making up a new BHA and tripping in hole back to the bottom of the well. This corresponds to about $56,000 in costs incurred. As highlighted above, bit balling poses a threat to achieving desired cost savings through efficient drilling operations, hence it is necessary to put in place effective mitigation strategies both in the well planning and drilling phase to tackle its undesirable effects. This includes optimal bit selection and hydraulics, effective mud conditioning (addition of clay inhibition material – KCl polymer, glycol), proper hole cleaning practices, appropriate monitoring, and control of drilling parameters – ROP, flow rate and weight on bit (WOB) etc.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock (0.30)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)