Wellhead Pressure Research Articles

GAS LIFT OPTIMIZATION OF A MATURE WELL IN NIGER DELTA, NIGERIA USING INCOMPLETE DATASET: A CASE STUDY

Well DEF, a well located in Niger Delta region of Nigeria was shut down for 7 years. On gearing towards re-starting production, different options such as installation of gas lift mechanism, servicing and installation of packers and valves were evaluated for possibility of increasing well fluid productivity. Hence, this research was focused on optimizing well fluid productivity using PROSPER through installation of continuous gas lift mechanism on an existing well using incomplete dataset; in addition, the work evaluated effect of gas injection rates, wellhead pressure, water cut and gas gravity on efficiency of the artificial lift mechanism for improved well fluid production. Results of the study showed that optimum gas injection rate of 0.6122 MMscf/day produced well fluid production of 264.28 STB/day which is lower than pristine production rate (266 STB/day) of the well. Also, increment in wellhead pressure resulted in decrease in well production, increase in water cut facilitated reduction in well fluid productivity while gas gravity is inversely proportional to well fluid productivity. Based on results obtained, authors concluded that Well DEF does not require gaslift mechanism hence, valves and parkers need to be re-serviced and re-installed for sustained well fluid.

Sensitivity Analysis of Multiphase Flow in a well Using PROSPER

Pressure drop in a vertical or deviated borehole has been found to be due to hydrostatic changes and friction as a result of the produced fluids flowing to the surface. When oil flows upwards, the flowing pressure along the tubing string drops, and this makes gas to start liberating. Thus, multiphase flow forms in the tubing string. Hence, adequate modelling of vertical lift performance is required to predict the pressure drop and subsequently the wellbore pressure because many factors are involved [1]. In this work, sensitivity analysis of multiphase flow in a well has been carried out with the aid of PROSPER in which the most accurate correlation was chosen from twelve selected built-in correlations present in the program to predict the pressure drop via gradient matching. A sensitivity analysis of the well was further performed to investigate the parameters such as tubing diameter, gas-oil ratio and wellhead pressure that were affecting the vertical lift performance of a high water cut well. The results obtained from the correlation matching showed that Dun and Ros [2] original correlation was the best fit correlation for the well. The results of the sensitivity analysis revealed that reduction of wellhead pressure from 600 psi to 400 psi could increase liquid rate by 41%. An adjustment of wellhead pressure was found to give the most significant impact on the production rate of the well as compared to other two parameters studied.

Design and application of well cementing technology based on the precise managed pressure balancing method in narrow pressure window hole sections

In the Sichuan Basin, the drilling of complex deep and ultradeep wells is restricted by the casing sequence. Multiple pressure systems are usually encountered in the same open hole section, and narrow safety density window is observed in vertical strata. The application of managed pressure drilling (MPD) technique which is often used in well drilling ensures the safe and efficient drilling, but it also brings about great challenges to the small-gap liner cementing at the lower part. Therefore, it is of great practical significance to research a cementing technology that can not only satisfy the quality requirement of small gap liner cementing, but also ensure the safe cementing in the strata with narrow safety density window. In this paper, a cementing technology based on precise managed pressure balancing method was proposed by referring to the successful application of MPD technique. According to the cementing design, the hydrostatic column pressure of annulus fluid is under-balanced (slightly lower than the formation pore pressure), and then a precise managed pressure drilling device is adopted to produce back pressure through wellhead restriction or apply wellhead compensation pressure, so that the balanced pore pressure can be reached in the process of cementing via the wellhead pressure and the flow friction of fluid in the annulus. After the cementing is completed, a certain compensation pressure is applied to the annulus continuously to prevent annulus channeling during waiting on cement caused by insufficient static pressure and slurry weight loss. After this technology was applied to an ultradeep exploration well in the Sichuan Basin, the qualification rate of borehole cementing quality reached 97%, and the well sections with good cementing quality accounted for 76%. In conclusion, this technology needs no additional equipment, and only by virtue of the MPD equipment, it can achieve safe cementing construction and cementing quality improvement under high displacement efficiency.

Effects of instantaneous shut-in of high production gas well on fluid flow in tubing

Abstract As the classical transient flow model cannot simulate the water hammer effect of gas well, a transient flow mathematical model of multiphase flow gas well is established based on the mechanism of water hammer effect and the theory of multiphase flow. With this model, the transient flow of gas well can be simulated by segmenting the curved part of tubing and calculating numerical solution with the method of characteristic curve. The results show that the higher the opening coefficient of the valve when closed, the larger the peak value of the wellhead pressure, the more gentle the pressure fluctuation, and the less obvious the pressure mutation area will be. On the premise of not exceeding the maximum shut-in pressure of the tubing, adopting large opening coefficient can reduce the impact of the pressure wave. The higher the cross-section liquid holdup, the greater the pressure wave speed, and the shorter the propagation period will be. The larger the liquid holdup, the larger the variation range of pressure, and the greater the pressure will be. In actual production, the production parameters can be adjusted to get the appropriate liquid holdup, control the magnitude and range of fluctuation pressure, and reduce the impact of water hammer effect. When the valve closing time increases, the maximum fluctuating pressure value of the wellhead decreases, the time of pressure peak delays, and the pressure mutation area gradually disappears. The shorter the valve closing time, the faster the pressure wave propagates. Case simulation proves that the transient flow model of gas well can optimize the reasonable valve opening coefficient and valve closing time, reduce the harm of water hammer impact on the wellhead device and tubing, and ensure the integrity of the wellbore.

Modelling of selected hydrodynamic and hydrochemical parameters of a geothermal water system: an example of Cieplice therapeutic waters

Article presents results of long-period observations made in the most interesting and perspective geothermal area of Poland. Moreover, Cieplice is one of the oldest spa resort in Poland where thermal waters are used for treating purposes for centuries. That is the only one region in Poland with geothermal waters in granitic rocks and this can be interesting for international readers. The region of Jelenia Góra-Cieplice has been considered a prospective area of geothermal water occurrence for many years. The earliest evidence of balneological use of these waters dates from the thirteenth century. Currently, they are being used for therapeutic purposes, and since 2014 also for recreation. The character of changes in intake discharge, water temperature and wellhead pressure observed in 1956–2019, as well as calculations of specific values (the mean, the minimum, the maximum and the standard deviation) have demonstrated considerable diversity and significant variation in these operating parameters. The main cause of changes in these parameters is changing intake operation conditions. Currently, thermal waters are being extracted chiefly from the deepened borehole C-1. Increased extraction from this intake has resulted in decreases in the temperature of thermal water from springs and borehole C-2 and a decline in their discharge or even the disappearance of their outflow. The exploitation of borehole C-1 in such conditions has also caused a drop in water pressure at its head (from 0.49 to 0.34 MPa) accompanied by an increase in water temperature (from 58 to 82 °C). The increase in water temperature is indicative of the presence of deep circulation waters in this intake. Based on the results of long-term (1963–2018) physico-chemical analyses of waters from particular intakes and deep boreholes, dominant chemical types have been distinguished: Na-HCO3–SO4 and Na–SO4–HCO3, containing fluorides and silica. By using chemical geothermometers, deposit temperatures of Cieplice thermal waters have been estimated (111–138 °C). The obtained results were verified by analysing the degree of saturation of these waters with selected rock-forming minerals by means of GeoT application. The deposit temperature estimated by modelling is c. 123 °C.

An integrated MILP model for optimal planning of multi-period onshore gas field gathering pipeline system

Onshore gas field gathering pipeline system (GPS) plays a key role in the onshore gas field production and is often constructed in stages due to the phased development of the gas field. However, the influence of phased development on the optimal design of GPS has been neglected in previous studies. Although some research on the optimization of gas field development strategy involves the multi-period construction of GPS, they simplify the characteristics of the gathering network and ignore some very important parameters.This study develops an integrated mixed-integer linear programming (MILP) model for optimizing multi-period GPS to determine the central processing facility (CPF) location, pipeline (routes and diameters) installation and expansions, well site-CPF connections, the flowrate of each pipeline, and the operating pressure of each node in each time period simultaneously. Taking minimum total construction cost as the objective function, the proposed model considers various operational and technical constraints related to multi-period construction and hydraulic characteristics, such as obstacles, three-dimensional terrain, pipeline topological structures, pipeline diameters, and wellhead pressure. Ant colony optimization is used for route optimization to provide parameters for the proposed model. A piecewise approximation method is employed to deal with the nonlinear terms of hydraulic equations. Therefore, the MILP model can be solved by the branch-and-bound algorithm to obtain the global optimal solution integrally. Finally, the model is successfully applied to three real-world gas fields. Compared with the actual construction scheme and other literature methods, the results prove the superiority of multi-period planning considering time.

A Hybrid Optimization Methodology Identifying Optimal Operating Conditions for Carbon Dioxide Injection in Geologic Carbon Sequestration

Prior to determining the optimal operating parameters for CO2 injection, conditions for both injection wellbore and storage formation should be evaluated; the build-up pressure induced by the CO2 injection could promote fractures in the storage formation, even collapsing the wellbore. In this study, a hybrid optimization methodology, which combined the proxy modeling and multi-objective optimization, was engaged in searching appropriate operating conditions for CO2 injection. The study utilized a fully coupled wellbore-reservoir (WR) model to simulate the CO2 injection scenarios. Three responses, such as pressure, temperature, and CO2 mass flow rate at the bottom-hole of injection wellbore, were investigated. To reduce the computational cost, the statistical proxy models were developed for approximating three responses. The developed fine-tuned proxy models revealed four influential factors; wellhead pressure, injected CO2 temperature, wellbore diameter, and permeability of a storage formation were significant in predicting three responses. Among these four influential factors, permeability was treated to be an uncertainty factor, while the other three factors were treated as tuning factors. According to acquired optimal solution sets, the optimum values for wellhead pressure and injected CO2 temperature were distributed around 10.0 MPa and 35 °C, respectively. For the wellbore diameter, its mean of optimal solutions was 0.1 m, and more solutions were concentrated at this mean value with a decrease in permeability.

Production optimization in well-6 of Habiganj gas field, Bangladesh: a prospective application of Nodal analysis approach

The overall performance of gas reservoirs and the optimization of production, as well as its sensitivity analysis, are affected by several factors such as reservoir pressure, well configuration and surface facilities. The Habiganj well no. 06 (HBJ-06) is one of the significant gas-producing vertical wells of the Habiganj gas field, currently producing 14.963 MMscfd of natural gas from the upper gas sand. The widely used Nodal analysis is an optimization technique to improve the performance and was applied for the HBJ-06 to increase its production rate by optimizing manners. By this analysis, each component starting from the reservoir to the outlet pressure of the separator was identified as a resistance in the system by evaluating their inflow performance relationship and vertical lift performance. The F.A.S.T. VirtuWell™ software package was used to perform this analysis, where the declinations of wellhead pressures were suggested as 1300, 1200, 1100 and 1000 psi(a) without any modification of the tubing diameter and skin factor. Hence, the respective optimized rates of the daily gas production were increased to 38.481, 40.993, 43.153 and 46.016 MMscfd. At the same time, the optimized condensate gas ratio was calculated as 0.07, 0.06, 0.06 and 0.05, associated with the optimized condensate water ratio of 0.11, 0.10, 0.09 and 0.08, respectively.

Dynamic characteristics of production pipe strings for gas storage wells

Abstract During gas production at gas storage wells, the high-speed flow of gas results in the vibration of production pipe strings, thereby leading to changes in the mechanical properties of production pipe strings and their destruction. To study the dynamic characteristics of pipe strings in gas storage wells, a fluid–structure interaction analysis model for production pipe strings in gas storage was established by considering the interaction effect of gas and pipe strings in the lateral and longitudinal directions and solved by using the method of characteristic. The results of the proposed model were validated through a similar experiment and comparison with the simulation results of published studies. The field data of a gas storage well at the Huabei Oilfield were used as bases to discuss the effects of gas production rate, wellhead pressure, pipe string thickness, and gas density on the dynamic characteristics of pipe strings. Results show that pipe strings are subject to a large displacement at the well-opening moment, and then the pipe string vibration is gradually attenuated. A large lateral deformation occurs in the middle and lower part of the pipe string. Pipe string displacement and deformation increases with an increase in gas production rate and decrease with an increase in wellhead pressure and pipe string thickness. With the increases of gas density, the fluid–structure interaction between the string and the gas intensifies, resulting in the increase of the displacement caused by the string vibration. These findings are of significant importance in reducing the vibration of pipe strings and protecting them during gas storage well production.

Coupled Fluid Flow and Geomechanical Modeling of Seismicity in the Azle Area (North Texas)

SummaryA series of earthquakes was recorded along a mapped fault system near Azle, Texas, in 2013. To identify the mechanism of seismicity, geologic, production/injection, and seismicity data are gathered to build a detailed simulation model with coupled fluid flow and geomechanics to model fluid injection/production and the potential onset of seismicity. Sensitivity studies for a broad range of reservoir and geomechanical parameters are performed to identify the influential parameters for injection wellhead pressure and earthquake data. A Pareto-based multi-objective history matching is performed using these influential parameters. The calibrated results are used to identify the controlling mechanisms for seismicity in the Azle area, North Texas, and their relationship to hydrocarbon production and fluid injection in the vicinity.Geomechanical interaction has a significant impact on seismicity in the Azle area. Unbalanced loading created by the difference in the net fluid injection and production on different sides of the fault seems to generate accumulation of plastic strain change, likely resulting in the onset of seismicity. Previous studies ignore fluid withdrawal from gas production. Thus, they seem to have significantly underestimated the fluid withdrawal rates, almost by an order of magnitude. The equivalent bottomhole-voidage fluid rate used in this study suggests a drop in history-matched reservoir pore pressure that is consistent with the observed tubinghead pressure trends. Pore pressure increases may not fully explain the seismicity near the Azle area. Instead, geomechanical effects and strain propagation to the basement appear to be the dominant mechanisms. The low fault cohesion and minimum effective horizontal stress obtained from history matching confirm that the faults must be near or at the critically stressed state before the initiation of fluid production/injection. A sensitivity analysis indicates that the minimum effective horizontal stress and fracture gradient play a critical role in the potential risk for seismicity related to fluid injection/production. A streamline flow pattern further shows that there is no fluid movement in the basement formation and the unbalanced loading from different sides of the fault is more likely the controlling mechanism for seismicity.

Effect of instantaneous shut-in on well bore integrity and safety of gas wells

The instantaneous shut-in of the gas well produces a transient flow phenomenon. The repeated pressure amplitude and pressure repeated changes will cause the vibration of the tubing and equipment, resulting in damage to tubing and accessory equipment. However, it is difficult to directly adopt the conventional transient flow model due to the particularity environment of the gas well bore. Based on the classical transient flow theory and mechanism of transient flow process in a gas well, a mathematical model explaining the transient flow phenomenon of gas well is established and the method of characteristics is adopted for numerical solution. The calculation results of sample show that, after the wellhead valve is closed instantaneously, the surge pressure is transmitted and gradually attenuates under the influence of frictional resistance, and reaches the balance pressure after a period of time. With the increase of valve closure time, the maximum value of wellhead pressure is reduced, and the time of peak value occurs is also delayed. When the gas well is shut in for a short time, the propagation speed of pressure wave is faster than that in the circumstance of shutting the gas well in a longer time. The transient flow model can accurately reflect the value of surge pressure, the cycle of surge pressure and attenuation law of pressure wave, which has a high reference value for studying the transient process and pressure distribution in the gas well bore.

Well-controlled dynamic hydrocarbon reserves calculation of fracture\u2013cavity karst carbonate reservoirs based on production data analysis

Fracture–cavity karst carbonate reservoirs have multiple storage space with irregular geometry and various scales, and this caused strong heterogeneity and complex flow characteristics. Accurately calculating the well-controlled dynamic reserves of this kind reservoir effectively is the basis to optimize oil field development plan and making the transformation measures of production well. In order to solve the problem that conventional well-controlled dynamic hydrocarbon reserves calculation method is not suitable for such type reservoirs, we applied a method based on production data analysis. Classification standard of oil well types is established based on the fracture–cavity reservoirs geological static and production dynamic characteristics. Conceptual characteristics of geological model and fluid flow pattern for different types of production wells are assumed. Calculation workflow for well-controlled reserves of fracture–cavity reservoir is established. In the process, some technical key points are proposed to improve accuracy of curve fitting, such as converting the bottom hole pressure from wellhead pressure, correcting the well control range and converting the PVT parameters at the pseudo-steady state. We verified correctness of this method by comparing the calculated results with numerical simulation results of actual production well. This method is well used to Tahe Oil field of Tarim Basin in China. The result shows that the well-controlled reserves quantitative calculation results through this method are in conformity with oil field actual understanding, and the remaining dynamic reserves mainly exist in the drainage area of the wells that drilled different reservoir bodies with good connectivity, especially at the top of large karst caves, and that is the target of further adjusting.

Real-Time Estimation and Management of Hydrate Plugging Risk During Deepwater Gas Well Testing

Summary Hydrate formation and deposition are usually encountered during deepwater gas well testing, and if hydrates are not detected and managed in time, a plugging accident can easily occur. In this study, we demonstrate a method for estimating and managing the risk of hydrate plugging in real time during the testing process. The method includes the following steps: predicting the hydrate stability region, calculating the hydrate formation and deposition behaviors, analyzing the effect of the hydrate behaviors on variations in wellhead pressure, monitoring the variations in wellhead pressure and estimating the hydrate plugging risk in real time, and managing the risk in real time. An improved pressure-drop calculation model is established to calculate the pressure drop in annular flows with hydrate behaviors, and it considers the dynamic effect of hydrate behavior on fluid flow and surface roughness. The pressure drops calculated at different times agree well with experimental and field data. A case study is conducted to investigate the applicability of the proposed method, and results show that with the continued formation and deposition of hydrates, both the effective inner diameter of the tubing and the wellhead pressure decrease accordingly. When the wellhead pressure decreases to a critical safety value under a given gas production rate, a hydrate inhibitor must be injected into the tubing to reduce the severity of hydrate plugging. It is also necessary to conduct real-time monitoring of variations in wellhead pressure to guarantee that the risk of hydrate plugging is within a safe range. This method enables the real-time estimation and management of hydrate plugging during the testing process, and it can provide a basis for the safe and efficient testing of deepwater gas wells.

Research on a Coupled Total-Flow and Single-Flash (TF-SF) System for Power and Freshwater Generation from Geothermal Source

In response to the twin development challenges of energy shortage and water-scarcity in worldwide arid to semi-arid regions with geothermal resources, a new combined power and freshwater generation system is proposed for geothermal energy utilization. In this system, a total-flow turbine (TF) is employed to be coupled with the traditional single-flash (SF) system and thereafter the coupled TF-SF system is investigated in this work. In addition to power generation, the exhaust steam from turbines are recovered to produce freshwater through condensation. Based on the novel designed system, the production of both power and water are studied under variable wellhead conditions, including variable wellhead pressures, temperatures, mass flowrates, and vapor qualities. The temperature of the separating point at which the total-flow expansion ends and the steam expansion starts is studied for optimal system output. In addition, the efficiency effects of the total-flow turbine on performance of the combined system is also investigated. The power generation comparison shows good power potential of the proposed TF-SF combined system. An effective total-flow turbine with an average efficiency of 65% can lead to an optimal power capacity, exceeding the traditional single-flash (SF) system by 23.7%. Moreover, more than 1/3 of total wellhead discharge can be recovered as desalinated freshwater by the naturally equipped condensation process of the power plant, showing extra benefit from geothermal energy utilization.

The Influence of Determining Factors on the Parameters of Gas-lift Operation of Flooded Gas Wells

The development of gas deposits at the final stage is usually complicated by watering production wells. With the advent of water in the formation product, the gas production rate decreases due to the decrease in the gas-saturated thickness of the reservoirs and the increase in pressure loss during movement of the liquid-gas mixture in the wellbore and flow lines as compared to the movement of gas only. Well operation is gradually becoming unstable, periodic with the subsequent cessation of natural flowing. The methods of operation of flooded wells are characterized. The use of the gas-lift method for the operation of flooded gas wells in depleted gas fields is justified. The effect of tubing diameter, wellhead pressure and water factor on the parameters of gas-lift operation of flooded wells is investigated. The research is carried out using the improved technique proposed by the authors and the PipeSim program for hypothetical (simulated) well conditions. The studies performed are presented in the form of graphical dependences of the production rate of reservoir gas, the minimum required gas production rate for the liquid to be taken from the bottom of the well to the surface, lift gas flow rate and bottomhole pressure on wellhead pressure, diameter of tubing and water factor. The research results indicate a significant coincidence of the values ​​of the calculated parameters of the gas-lift operation of the watered well according to the proposed methods and the PipeSim program. Using the research results, it is possible to select the optimal diameter of the tubing string and evaluate the value of formation gas flow rate and gas-lift flow rates for various values ​​of water factor and wellhead pressure.

Visco-inertial gas flow through wellbore cement fractures

Understanding the nature of fluid flow through fractured wellbore cement is fundamental for evaluating the leakage potential and risk assessments of leaky wellbores. In this study, the conditions that require considering visco-inertial flow for describing the gas flow through wellbore cement fractures were investigated. Nitrogen gas flow tests were conducted on fractured cement samples under varying pressure conditions and flow rates, covering both viscous and visco-inertial flow regimes. The data substantially deviated from Darcy's law at higher flowrates and were well-fit to Forchheimer's equation for visco-inertial flow. The inertial coefficient and critical Reynolds number were expressed as a function of the hydraulic aperture. The empirical function obtained from the experiments was used as an input to numerical simulations which showed the significant role of visco-inertial flow in wellhead pressure build-up and leakage rates, and demonstrated the importance of visco-inertial flow when modeling gas flow through wellbore cement fractures.

Near Real-Time Hydraulic Fracturing Event Recognition Using Deep Learning Methods

Summary This paper provides the technical details of developing models to enable automated stage-wise analyses to be implemented within the real-time completion (RTC) analytics system. The models—two of which use machine learning (ML), including the convolutional neural network (CNN) technique (LeCun et al. 1990) and the U-Net architecture (Ronneberger et al. 2015)—detect the hydraulic fracture stage start and end, identify the ball seat operation, and categorize periods of pump rate. These tasks are performed on the basis of the two reliably available measurements of slurry rate and wellhead pressure, which enable the models to run automatically in real time, and also lay the foundation for further hydraulic fracturing advanced analyses. The presented solution provides real-time automated interpretations of hydraulic fracture events, enabling auto-generation of key performance indicator (KPI) reports, dispelling the need for manual labeling, and eliminating human bias and errors. It replaces the manual tasks in the RTC workflow/data pipeline and paves the way for a fully automated RTC system.

Prediction and Analysis of Wellbore Temperature and Pressure of HTHP Gas Wells Considering Multifactor Coupling

In the production process of high-temperature and high-pressure gas wells, it is very important to understand the changes of the temperature and pressure parameters in the wellbore with the depth of the well. Based on the conservation of fluid energy, momentum, and mass in the wellbore, considering the influence of high-temperature and high-pressure gas wells on the temperature and pressure of the wellbore under the coupling of fluid velocity, density, and Joule–Thomson effect, a wellbore temperature and pressure prediction model was established based on this. Then, we could obtain wellbore temperature and pressure distribution along the well depth. The comparison with the actual wellbore data of Tarim X gas well and XX well in Southwest China shows that the calculation result of the multifactor coupling model is less than 3% of the field measured data, which verifies the accuracy of the multifactor coupling model result. Based on this, the effects of different gas production and production time on the temperature and pressure of high-temperature and high-pressure gas well boreholes were analyzed. The results show that for the Tarim X gas well, when the gas production is 80 × 104, 90 × 104 and 100 × 104 m3/day, the corresponding wellhead temperatures are 56.1, 65.3, and 69.8 °C; the corresponding wellhead pressures are 62.4, 62.2, and 62.0 MPa. When the production time is 1 day, 10 days, and 20 days, the corresponding wellhead temperatures are 61.5, 63.6, and 64.8 °C, respectively; the corresponding wellhead pressures are 63, 62.8, and 62.4 MPa.

Geological controls on coalbed methane accumulation and optimisation strategy for gas productivity: a case study in eastern Ordos Basin, China

Drainage conditions can significantly affect the coalbed methane (CBM) production, which is accomplished by reducing the gas partial pressure in the coal seam. This can be achieved by pumping the formation water or gas injection. In this study, the Baode region is selected to study the drainage conditions and production characteristics on the early stage of CBM production. The temporal trends of water production, wellhead pressure and gas production have been analysed. Results show that the favourable burial depth for CBM accumulation between 500 and 700 m. Sandy mudstone and mudstone are beneficial to CBM preservation. The wellhead pressure should be maintained between 0.4 MPa and 1.0 MPa, and the optimal range of wellhead pressure lies between 0.5 and 0.8 MPa for stable production. The gas production increases with increased water production when the wellhead pressure has become progressively stable in the middle phase of early stage. [Received: September 9, 2018; Accepted: October 24, 2018]

Artificial Intelligence Transforms Offshore Analog Fields Into Digital Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195027, “Turning an Offshore Analog Field to Digital Using Artificial Intelligence,” by Roberto Espinoza, SPE, Dragon Oil, and Jimmy Thatcher and Morgan Eldred, Digital Energy, prepared for the 2019 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 18–21 March. The paper has not been peer reviewed. Currently, no cost-effective method exists to efficiently, reliably, and accurately capture analog meter readings in a digital format. This paper details how artificial intelligence was used to capture analog field-gauge data with a dramatic reduction of cost and an increase in reliability. This solution was implemented in the Cheleken oil field in the Caspian Sea offshore Turkmenistan. During the field trial, operators were required to take pictures of the gauges at given intervals and upload the photos to the application. After an innovative process of calibration, the acquired images were processed using artificial intelligence and deep-learning computer techniques. Introduction Digitizing an oil field is an exciting but costly exercise that requires close supervision to avoid inefficiency. Best results are achieved when priorities and objectives are defined early in the project. For instance, if the objective is cost savings, then digitization should be applied in a manner different from that used in production optimization. Regardless of the objective, implementation of the digital oil field is a constant battle against cost and time. The most effective value is achieved without 100% digitalization. Often this fact is overlooked, and during the digitization of the field, extra cost is incurred without tangible improvements in the value because the oil field is not homogeneous and not all parameters need to be monitored or optimized with digital devices. For instance, 90% of production comes from 10–20% of the wells in most fields. In digitizing by priority, early value can be brought to the project as stakeholders are encouraged to grow the digitization effort from a monitoring perspective to value maximization. Automating Input Data A user able to predict production has the ability to maximize future revenue. However, continuous metering of production is very costly. Installing a multiphase meter on each well is a luxury afforded in only a few fields with very high production. Instead, most fields need to share metering facilities by using a test manifold. Wells are then tested with a certain frequency and the daily rate is estimated on the basis of these tests. Commonly, well production between tests is assumed to be constant until a new test is conducted. This assumption can be improved with the use of a calculated value from a virtual flowmeter (VFM). One of the more sensitive input parameters for this VFM is the wellhead pressure. In some cases, when the wellhead pressure is measured manually by observing analog gauges, human errors are incurred (in terms of visual, typographical, and duplication errors). The methodology used in this paper eliminates all human errors while reducing the time and cost of acquisition when acquiring pressure and temperature readings from analog gauges by using computer vision. These improvements in the input parameters resulted in a more-reliable prediction of production rates from the VFM.