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Collaborating Authors
SPE Nigeria Annual International Conference and Exhibition
Abstract Non-Darcy skin is always present in the gas, gas-condensate, and high Gas Oil Ratio (GOR) oil wells, increasing as the rate increases. However, the reverse is true in a well with a loading skin. This paper outlines the interpretation procedure and unmasking of the non-Darcy skin in a loading well with a new calculation approach. A rate test for a gas or gas-condensate well with a pressure transient test (PTT) is required for well-test interpretation, and the diagnostic and the matched well production history plot provide the nominal or rate-dependent skin. The effective skin comprises completion, non-Darcy, and loading skins in a well with decreasing effective and loading skins. This approach focuses on matching the production history plot to provide the rate-dependent skins to determine the loading and completion skins. It becomes impossible to determine reservoir parameters with a masked radial flow regime. When compounded with serious liquid-loading skin, non-Darcy skin determination becomes another challenge. In this scenario, Ramey's method and Spivey's for determining non-Darcy skin become insufficient because the former deals with an increasing non-Darcy skin only; in this case, we have a decreasing skin, and the latter does not account for a loading skin. This study resolves the limitation of both methods by accounting for the loading skin and unmasking the non-Darcy skin. With the new formulation for effective skin, the reservoir parameters can be determined from the general flow regime equations. The loading-skin rate-mitigation strategy proves successful in well recovery. This approach is utilized with a loading-skin mitigating rate to recover well that would have quit on production. The non-Darcy skin effect and the loading-skin curves reveal a minimum loading-skin mitigating rate for improved productivity and overcoming Ramey and Spivey methodsโ limitations.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Evaluation Studies of KCl and Amino Acid Mixtures for Clay Stabilization and Rheological Enhancement of Water-Based Fracturing Fluids
Duartey, K. O. (Department of Petroleum and Natural Gas Engineering, University of Energy and Natural Resources, Sunyani, Ghana, West Africa) | Quainoo, A. K. (Department of Geoscience and Geological and Petroleum Engineering, Missouri University of Science and Technology, Rolla, MO, United States) | Darko, C. K. (Department of Geoscience and Geological and Petroleum Engineering, Missouri University of Science and Technology, Rolla, MO, United States)
Summary Conventional stabilizers such as inorganic salts in water-based fluids are restricted for use in gas and oil shales drilling and hydraulic fracturing for drilling due to environmental, economic and performance concerns. For example, 2% use of KCl, a commonly used inorganic salt, contains an excess of 9500ppm chloride. This is considered high and toxic. Apart from environmental problems, KCl inhibiting solutions tend to negatively affect the rheology of the water-based fluids, posing a dilemma for industry operators. The clay and rheological stabilizing effects of KCl and amino acid mixes for hydraulic fracturing operations were investigated in this study. The stabilizing and rheological potentials of mixes of KCl and organic compounds have proven to be superior to the separate compounds in studies. The KCl was used in the study at safe quantities (1%) to prevent toxicity concerns. In this study, the inhibition potentials of KCl+ Arginine and KCl + Alanine solutions, mixed approximately at ecologically safe quantities, were tested at different bentonite wafers using M4600 Linear swell at 25ยฐC and 1000psi in the work. Furthermore, rheological studies on bentonite-based suspensions were carried out using a high-precision Discovery Hybrid Rheometer (DHR-1). This was done to monitor the flow parameters of the inhibiting suspensions and their anti-swelling effects on the bentonite component of the prepared fracturing fluid. The effects of the mixtures were also compared to that of KCl, Arginine and Alanine inhibition solutions. Herschel-Bulkley's model was also used to determine the flow characteristics. After 24 hours of testing, the swelling findings reveal that KCl+ Arginine/KCl + Alanine treated fracturing fluids significantly affect the clay stabilization and rheological properties of the fracturing fluid. The study provides basic information on the inhibition potentials of KCl and natural amino acid mixtures in water-based fracturing fluids for clean clay stabilization.
- North America > United States (0.46)
- Africa > Nigeria (0.28)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.39)
A Digitized Tool for Well Candidate Selection for Matrix Acidizing in Sandstone Reservoir
Okologumw, W. C. (Department of Petroleum Engineering, Federal University of Petroleum Resources Effurun, Delta State, Nigeria) | Onyeoru, J. O. (Department of Petroleum Engineering, Federal University of Petroleum Resources Effurun, Delta State, Nigeria)
Abstract Matrix acidizing is a well-stimulation that has evolved and is still used to increase productivity when the productivity index drastically decreases and the production rate declines. A candidate well-stimulation selection method and software are suggested in this work. The process is based on technical, workover complexity, production decline curve analysis (for future forecasting), and economics since candidate selection must be rigorous. Production data from four onshore Niger Delta stimulation candidate wells were used to validate the software developed. R-factor, productivity index, and flow efficiency were the technical parameters used, and eleven (11) indicators were used for workover complexity evaluation. The future forecast was done using the production decline curve analysis and different economic indicators such as the Internal Rate of Return (IRR), the Net present value (NPV), and the Payback time. Profitability Index (PI) was used for analysis and make decisions. All wells analyzed in this study met the technical parameter criteria, making each well a potential candidate; hence, further studies can be conducted. From further reviews based on the author selection criteria carried out with regard to production trend (decline curve analysis) and economics, it was seen that WELL XX-01 was ranked first due to its shortest payback time of 2.0899 months and highest NPV of $23,636,983, WELL XX-03 was ranked next, having a payback of 2.2472 months and an NPV of $9,627,221, WELL XX-02 was ranked following having NPV of $7,260,917 and a payback of 2.2560 months and lastly, WELL XX-04 having a payback time of 2.3615 months and NPV of $6,777,548.
Modeling Two-Phase Flow in Vertical and Deviated Wellbores Using Machine Learning Method
Elgaddafi, R. M. (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait/ Petroleum Engineering Department, University of Oklahoma, Norman, Oklahoma, United States) | Ahmed, R. (Petroleum Engineering Department, University of Oklahoma, Norman, Oklahoma, United States) | Salehi, S. (Petroleum Engineering Department, University of Oklahoma, Norman, Oklahoma, United States) | Alsaba, M. T. (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait) | Biltayib, B. M. (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait) | Ikeokwu, C. C. (Hameyo, Lagos State, Nigeria) | Amadi, K. W. (Petroleum Engineering Department, Australian University, Kuwait City, Kuwait)
Abstract The worst-case discharge during a blowout is a major concern for the oil and gas industry. Various two-phase flow patterns are established in the wellbore during a blowout incident. One of the challenges for field engineers is accurately predicting the flow pattern and, subsequently, the pressure drop along the wellbore to successfully control the well. Existing machine learning models rely on instantaneous pressure drop and liquid hold-up measurements that are not readily available in the field. This study aims to develop a novel machine-learning model to predict two-phase flow patterns in the wellbore for a wide range of inclination angles (0 โ 90 degrees) and superficial gas velocities. The model also helps identify the most crucial wellbore parameter that affects the flow pattern of a two-phase flow. This study collected nearly 5000 data points with various flow pattern observations as a data bank for model formulation. The input data includes pipe diameter, gas velocity, liquid velocity, inclination angle, liquid viscosity and density, and visualized/observed flow patterns. As a first step, the observed flow patterns from different sources are displayed in well-established flow regime maps for vertical and horizontal pipes. The data set was graphically plotted in the form of a scatter matrix, followed by statistical analysis to eliminate outliers. A number of machine learning algorithms are considered to develop an accurate model. These include Support Vector Machine (SVM), Multi-layer Perceptron (MLP), Gradient Boosting algorithm, CatBoost, and Extra Tree algorithm, and the Random Forest algorithm. The predictive abilities of the models are cross compared. Because of their unique features, such as variable-importance plots, the CatBoost, Extra Tree, and Random Forest algorithms are selected and implemented in the model to determine the most crucial wellbore parameters affecting the two-phase flow pattern. The Variable-importance plot feature makes CatBoost, Extra Tree, and Random Forest the best option for investigating two-phase flow characteristics using machine learning techniques. The result showed that the CatBoost model predictions demonstrate 98% accuracy compared to measurements. Furthermore, its forecast suggests that in-situ superficial gas velocity is the most influential variable affecting flow pattern, followed by superficial liquid velocity, inclination angle, pipe diameter, and liquid viscosity. These findings could not be possible with the commonly used empirical correlations. For instance, according to previous phenomenological models, the impact of the inclination angle on the flow pattern variation is negligible at high in-situ superficial gas velocities, which contradicts the current observation. The new model requires readily available field operating parameters to predict flow patterns in the wellbore accurately. A precise forecast of flow patterns leads to accurate pressure loss calculations and worst-case discharge predictions.
- North America > United States > Oklahoma (0.29)
- Europe > United Kingdom > England (0.28)
- Information Technology > Artificial Intelligence > Machine Learning > Ensemble Learning (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Neural Networks > Perceptrons (0.69)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Support Vector Machines (0.55)
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)
Decarbonization: Economic Analysis of Powering a Filling Station with Solar Panel System in Nigeria
Ayodele, Emmanuel (Niger Delta Power Holding Company) | Okoli, Kingsley (Saint Petersburg Electrotechnical State University LETI) | Ibrahim, Bilal (UNIPORT) | Ebere, Emmanuella (University of Port Harcourt) | Akinyemi, Oluwaferanmi (Federal University of Technology, Minna) | Wosu, Nwonodi (Federal Polytechnic of Oil and Gas)
Abstract From the refineries to the filling stations to the vehicles themselves, the transportation industry is responsible for one of the highest levels of emissions in the contemporary era. These emissions come from vehicles that run on diesel, gasoline oil, and premium motor spirit. This study is centred on the reduction of carbon emissions at filling stations for petroleum products as a means of lowering a facility's overall carbon footprint. Throughout the study, data on the overall energy output of the filling station was collected and the costs associated with solar energy systems were analysed. The cost of installation of a solar energy system, as well as the cost of maintenance and the life cycle of the alternative source of energy, in this case, solar energy, are factored into the study. During an investigation into the economic viability of substituting a solar system for diesel power generators, a total of one hundred (100) refuelling stations in Nigeria's Niger Delta region (Port Harcourt) were considered. The paper shows a breakeven period of 1-4 years for different filling station designs investigated when power is supplied with a solar system. The cost-failure theory was also evaluated and found to be 441 Naira for the cost of diesel if the system were termed inefficient. This paper presents a feasibility study that demonstrates an efficient method for lowering the carbon emissions footprint caused by diesel powered filling stations.
- Africa > Nigeria > Rivers State > Port Harcourt (0.27)
- Africa > Nigeria > Niger Delta (0.24)
- Energy > Renewable > Solar (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
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.
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.
Abstract Production from several matured oil and gas fields is impacted by high water cut. Common causes of excess water production in wells are coning, inflow through fractures and poor cement quality behind casing. Operators always aim at increasing the recovery of oil and gas and prolong well life in the absence of or negligible water cut. Polymeric gel system is a clear fluid formulated with low-molecular-weight polymer which allows penetration into matrix pore spaces for complete shut-off. Its low viscosity prior to crosslinking aids its injectivity; after placement in small openings such as pore throats and channels in cement behind casing, the final product is a rubber-like ring gel which penetrates formation matrix to reduce permeability and eventual shut-off flow. This paper focuses on the application of polymeric gel solution designed to shut off water production in two wells in Niger Delta. The candidate wells were carefully selected following a comprehensive review of the well schematic, petrophysical information and the reservoir performance monitoring logs. Based on the results of the data analyzed, polymer gel system was recommended. The required laboratory tests were conducted to confirm gelation time prior to field deployment. Coiled tubing and thru tubing inflatable packer were the preferred deployment method for precise treatment placement. The wells were shut-in for five days and surface samples were collected and kept in the water bath under downhole temperature conditions to allow curing of the treatment. The wells were opened after the curing time, and pressure tested against cured treatment system downhole and held for 10mins. The positive results from the pressure tests in both wells showed that total shut-off of the existing perforations were successful. The wells were thereafter re-perforated at shallower depths and production sustained on both wells.
- Africa > Nigeria (1.00)
- North America > United States > Texas (0.46)
Abstract Weak and loose sand grains that make up oil and gas formation matrix can be strengthened by chemical bonding while still maintaining the desired permeability for optimum production. This case study involves a well with high sand production rate that led to surface equipment failure and eventual shut down of an entire flow station for months. This paper discusses the application and results of the deployment of a chemical sand consolidation fluid system on the candidate well. The process involves mixing and squeezing the system into the formation and allow it to set. Once cured, the system forms an artificial core with a high compressive strength and permeability thereby preventing the well from producing sand. The system is externally catalyzed with two major additives in the mix that work in synergy to enhance wettability of the formation materials and to increase unconfined compressive strength of unconsolidated sand. In selecting a candidate well, formation data including bottom hole temperature and pressure, interval length, permeability, porosity and mineralogy were carefully studied and analyzed to build a geo-mechanical model that predicts minimum unconfined compressive strength (UCS) for sand sand-free production. Laboratory model and sanding assessment were carried out by developing cores using actual well formation materials. The fluid system was prepared and flown through cylindrical cores in the laboratory under reservoir conditions. Actual field deployment was carried out using coiled tubing. The well was shut-in for 24hrs after treatment and opened up for sand free production. Post treatment analysis of the surface cores made during deployment yielded a UCS of 789Psi and permeability to brine that stabilized at 1963mD.
- Africa > Nigeria (0.68)
- North America > United States > Texas (0.28)