Ali Khan, Farhan (Weatherford) | Antonio Sierra, Tomas (Weatherford) | Gabriel Imbrea, Robert (Weatherford) | Robin Edwards, Michael (Weatherford) | Al-Rushoud, Ali (Kuwait Oil Company) | Al-Abdulhadi, Fahad (Kuwait Oil Company) | Shehab, Abdulaziz (Kuwait Oil Company) | Al-Ajeel, Fatemah (Kuwait Oil Company)
Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline. A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches. Operations were divided into six parallel processes as follows: 1. Equipment logistics 2. Gravel foundation preparations 3. Concrete foundation installations 4. Unit Pre-assembly 5. Pre-assembled units dispatches 6. Final unit installations Daily output targets were set for each process prior to the commencement of operations.
Multilateral drilling technology offers a highly effective method of enhanced oil recovery in fields characterized by complicated geological structure. This paper describes the analysis of sidetracks in an open hole by annular ledge formation with the use of a downhole motor in multilateral wells in Vostochno-Messoyakhskoye field.
Since May 2018, more than 130 sidetracks have been drilled in Vostochno-Messoyakhskoye field with the use of bottomhole assembly (BHA) with a downhole motor in open hole by annular ledge formation. The fundamental difference between this method and conventional sidetracking with a downhole motor is that during sidetracking the entire drill string constantly rotates, rather than just bit rotation produced by downhole motor operation. In the process of technology introduction a comparison was made on how different downhole and geological conditions influence the time and performance results.
The technology introduction resulted in the sidetracking time reduction from 9 hours to just 3 to 4 hours.
A number of additional advantages of sidetracking with annular ledge formation were confirmed in the process of operations:
The constant rotation of the drill string enables smooth weight transfer to the bit smooth, without failures. This contributes to effective and uniform ledge formation. Such sidetracking can be carried out at an extended length of open hole when it is difficult to ensure a free movement of the BHA which is necessary of conventional sidetracking. Constant rotation mitigates the risk of differential sticking. More favorable conditions are created for BHA movement in an interval of the holes diversion and subsequently for liner running in. It is possible to sidetrack with the use of a stiff BHA including a complete set of logging tools. In case of conventional sidetracking, it is preferable to use a short and flexible BHA.
The constant rotation of the drill string enables smooth weight transfer to the bit smooth, without failures. This contributes to effective and uniform ledge formation.
Such sidetracking can be carried out at an extended length of open hole when it is difficult to ensure a free movement of the BHA which is necessary of conventional sidetracking.
Constant rotation mitigates the risk of differential sticking.
More favorable conditions are created for BHA movement in an interval of the holes diversion and subsequently for liner running in.
It is possible to sidetrack with the use of a stiff BHA including a complete set of logging tools. In case of conventional sidetracking, it is preferable to use a short and flexible BHA.
The experience gained in Vostochno-Messoyakhskoye field can be extrapolate to other fields where multilateral wells are drilled with annular ledge formation.
Al-shammari, Baraa Sayyar (Kuwait Oil Company) | Rane, Nitin (Kuwait Oil Company) | Ali, Shareefa Mulla (Kuwait Oil Company) | Sultan, Aala Ahmad (Kuwait Oil Company) | Al Sabea, Salem Hamad (Kuwait Oil Company) | Al-naqi, Meqdad (Kuwait Oil Company) | Pandey, Mukul (Weatherford) | Solaeche, Fernando Ledesma (Weatherford)
The Kuwait Integrated Digital Field project for Gathering-Center 01 (KwIDF GC-01) at Burgan Field acquires real-time data from wells and processing facilities as input for its production-surveillance program. Live data from the field is fed into an integrated production model for analyzing and optimizing pump performance. An automated workflow process generates alarms for critical well and facility parameters to identify wells with potential scaling issues. KwIDF workflows are integrated with updated well models to visualize the effect of scale build up on the wellhead performance and thereby assist in quantifying the associated production losses caused by scale deposition. A sensitivity analysis is also performed to identify current and optimal pump operating conditions and prioritize scale cleaning jobs.
The exception-based surveillance of key real-time parameters for wells utilizing electrical submersible pumps (ESPs) in Burgan field has significantly improved diagnostics of scale deposition at wellhead chokes and flowlines. Automated workflows calibrate an integrated production model in real-time, which enables engineers to run a quick analysis of current pump operating conditions and make a proactive plan of action. The application of real-time data and automated models has aided the operator's production team in making informed and timely decisions that enable them to run pumps at optimal operating conditions, with the result that they are able to sustain well production at target levels.
This paper describes an innovative approach to applying real-time data and integrated models in an automated workflow process for enhancing capabilities to diagnose scale deposition in the surface flow network. Examples are presented to demonstrate the application of integrated technology for identifying scaling at wellhead chokes and flowlines and prioritizing a scale removal program for optimizing pump performance.
The complex downhole tools in upstream oil & gas industry are subjected to internal and external pressure due to variety of fluids ranging from drilling mud to reservoir fluids which dictates downhole tool performance in the well bore. Extensive laboratory testing is needed to quantify the downhole tool performance which can be cost and time intensive process. An alternative approach is to conduct numerical simulations to investigate the real operating scenarios and predict the downhole tool performance including high pressure high temperature (HPHT) conditions which are difficult to set up in laboratory environment. The objective of this work is to underscore importance of advanced simulation technology in evaluating down-hole tool performance. To attest usage of simulations two examples are presented, the first one is utilization of computational fluid dynamic (CFD) simulations to analyze the performance of flow regulation inflow control device (ICD) for challenging multi-phase flow operations to predict onset of cavitation and second is to analyze the hold-down slip indentation dynamic operation using advanced explicit finite element simulation methodology.
The completions ICD tool aids in maintaining uniform inflow of production fluid in horizontal and deviated wellbores by providing pressure drop utilizing nozzles. Advanced flow modeling is critical to understand the flow behavior through ICD and check for onset of phase change/cavitation of the production fluid. Three dimensional CFD simulations are conducted using pressure based algorithm for numerically solving mixture multi-phase model coupled with Reynolds-Averaged Navier-stokes (RANS) equation and k-ε turbulence model to predict onset of cavitation for given operating conditions.
The dynamic hold down slips operation is important to set up a packer and during this step casing gets indented with the carbide buttons. The setting up of slips can cause localized permanent deformation in the casing and estimating the setting force along with hanging load capacity of the slip system is important to avoid permanent damage to the casing. Three dimensional explicit non-linear FEA is conducted to predict the stresses and deformations in the casing.
Multi-phase simulations for ICD are conducted with different nozzle configurations and operating conditions. CFD results highlighted velocities, pressure drop through ICD and also indicated onset of cavitation for provided operating conditions. Advanced modeling results helped in configuring the ICD and operating conditions to avoid cavitation.
FEA conducted for hold-down slip predicted the load needed to cause ~0.030" button indentation on casing and also provided insights in collapse analysis of the casing. A detailed presentation of the stress field helped in identifying the loading limits for this system and also probable failure locations due to loading. Advanced simulations helped in assessing the downhole tool performance for given operating envelopes and provided critical insights that delivered confidence in utilizing these tools for field operations.
Bassam, Abdul-Aziz (Kuwait Oil Company) | Al-Besairi, Ghazi (Kuwait Oil Company) | Al-Dahash, Sulaiman (Kuwait Oil Company) | Sierra, Tomas (Weatherford) | Mohamed, Assem (Weatherford) | Heshmat, Kareem (Weatherford)
The demand for digital oil field solutions in artificially lifted wells is higher than ever, especially for wells producing heavy oil with high sand content and gas. A real-time supervisory control and data acquisition solution has been applied in a large-scale thermal pilot for 28 instrumented sucker rod pumping wells in North Kuwait. This paper focuses on the advantages of real-time data acquisition for identifying productionoptimization candidates, improving pump performance, and minimizing down time when using intelligent alarms and an analysis engine. Real-time surveillance provided a huge amount of information to be analyzed and discussed by well surveillance and field development teams to determine required actions based on individual well performance. Controller alarms and intelligent configurable alarms in one screen enabled early detection of unexpected/unwanted well behavior, re-investigating well potential, and taking necessary actions. The challenge was to handle heavy oil, sand, and gas production, maintain all wells at optimum running conditions before and after steam injections, and take into consideration the effect that injections would have on nearby wells. Recording in the database a "tracking item" for each well event enabled review and evaluation of the wells and creation of optimization reports. The daily, 24-hour surveillance of the wells resulted in observing common problems/issues on almost all wells and other individual issues for specific wells.
To optimize production of a supergiant field, operators require an integrated approach to production forecasting that incorporate subsurface models of multiple reservoirs, well performance, surface equipment and facility constraints. This helps asset managers plan and optimize production on a well-by-well basis to achieve maximum system deliverability. This paper addresses challenges of integrating huge amounts of data, model framework and automated workflows to identify opportunities in debottlenecking, production target sustainability and deliverability.
The integrated production system model involves a simplistic bottom-up approach, in which advanced integration of subsurface and surface elements was facilitated through automated workflows within a digital oilfield system. These automated workflows enable converting multiple reservoir simulation output files to a standard format and mapping of common well names in simulation outputs and in well and facility models. An event-controlled scheduling process in a single working environment enabled analysis of production targets in realistic facility situations for future time steps. The decline in reservoir pressure is modeled, with new well performance in facility model based on changing reservoir conditions.
This automated environment has been adapted to evaluate two giant onshore fields encompassing multiple reservoirs, thousands of wells and numerous distributed-process facilities. The forecasting process confirms deliverability of planned and sustainable production and identifies opportunities for additional field potential, thus facilitating CAPEX optimization for future well costs. The integrated asset forecast was successfully carried out over a five- year timeframe at monthly intervals. One of the most important results obtained from such a forecast simulation was obtaining the maximum feasible rates that can be expected from the asset for each month during the next five years. This collaborative solution has successfully demonstrated the value of data and software integration, and addressed the challenges in integrated production forecasting. The results prove that this is a powerful tool for short- and medium- term forecasting, enabling asset managers to plan field operations, drilling, workovers, and facility improvement projects
This paper describes an integrated production forecasting setup. The case study explains process steps, challenges, simplification and results. The modeling and integration process enables the asset operator to plan remedial subsurface and surface projects to sustain planned rates over time. The forecasting process helps in quick business decision making, thus minimizing uncertainties in deliverability of future production mandates and highlights production-enhancement opportunities.
This paper describes an efficient approach for estimating well potential using advanced, automated workflows for a large field with more than a thousand well strings from multi-layered reservoirs having different characteristics. This paper provides insight into reservoir guidelines, well performance, and surface facility constraints using the integrated asset operations model (IAOM) to compute well potential.
The IAOM tool automates an engineering approach in which reservoir management guidelines, in conjunction with calibrated wells and a network model, are used to estimate well potentials. This process incorporates the interaction among various components including wellbore dynamics (Inflow performance and well performance), surface network backpressure effects and well performance key parameters, such as GOR and water cut. This engineered workflow computes the well potential corresponding to each guideline and constraint.
This engineered workflow has reduced the time to compute the well potential rate from 3-4 weeks to just 2 hours for this large field, reducing computation time by more than 95%. This workflow helped engineers to avoid tedious manual calculations on a well-by-well basis and allowed them to focus on engineering, analytical, and optimization problems. The confirmation of calculated well potential rates using the updated surface network model helped in finalizing the business scenarios such as field-capacity tests. For example, the accuracy of predicted results in a zonal capacity test was approximately 98% using this engineered workflow approach. The value derived from this engineering logic using validated physical models supported the business plan and further identified key candidates for production optimization without heavy dependence on drilling additional wells, leading to cost optimization. This automated workflow ensures the use of updated physical models and maintains higher accuracy of results. This digital system-based data-management process supports data governance objectives.
This enhanced workflow supports corporate objectives of standardization for a work process to set well allowable, in line with the operator's integrated reservoir management (IRM) initiative.
Reddicharla, Nagaraju (ADNOC Onshore) | Ali, Mayada Ali Sultan (ADNOC Onshore) | Cornwall, Rachelle (ADNOC Onshore) | Shah, Ankit (Weatherford) | Soni, Sandeep (Weatherford) | Isambertt, Jose (Weatherford) | Sabat, Siddharth (Weatherford)
Digital oil fields have seen major advancements over the past ten years, with the goal of integrating and optimizing the loops of production operation, production optimization, well and reservoir surveillance based on real-time data and model-based workflow automation capabilities. This paper discusses how ADNOC onshore has successfully implemented model-based digital oil field workflows in all its producing fields and describes the process of migrating these workflows to a data-driven platform for improved decision making.
In the existing workflows, data-driven diagnostic analytics are applied to validate well performance and accelerate the process of identifying underperforming wells and inefficiencies. These data-driven diagnostic analytics were implemented on a digital oilfield workflow platform where data is aggregated from disparate data sources consisting of non-real time well data, well events, well test history, MPFM, interpreted PTA, reservoir simulation, well integrity and wells tie-in data, along with continuous real-time sensor and model-generated data. The analytics are mapped with workflows and asset hierarchy. The linear regression method is used to forecast trends for water cut and GOR based on historical data.
Diagnostic analytics have been successfully configured for a giant onshore field having more than a thousand wells and multiple reservoirs. The alarm diagnostic map is generated based on tolerance and difference with exceptions. The solution framework has a common data abstraction layer and integration. A built-in visualization engine allows customization based on user preferences, linking multiple screens and analytics. Well test validations are improved for non-instrumented wells by using diagnostic based on more than 10 years of well test history. Well level allocation analytics allow comparisons between real-time export meter and terminal figures at the same timestamp, based on well models. For model calibration, wellhead pressure estimation from the last valid model was introduced. Well surveillance and management diagnostic analyze wells which are operating on critical/sub-critical condition and increasing water cut based on models and measured data. The combination of reservoir simulation data, PTA, bottom-hole surveys and estimated data from well models provides insights to validate quality of simulation data and reduce uncertainty in well models. Compartment and reservoir-wise VRR diagnostic enable asset operators to take faster remedial actions for reservoir performance management. These analytics complemented traditional model-based automated workflows for identifying wells for optimization.
A digital oilfield solution platform has been leveraged to implement diagnostic analytics in the first phase and to provide a road map to migrate it to next-generation data-driven platform that has more predictive capabilities. This paper discusses solutions and data integration frameworks, analytics visualization, integration with model-based workflows, value cases and the road map ahead.
Estimating hydraulic frictional loss in narrow annuli is challenging, especially for deepwater offshore wells with extremely narrow drilling margins. The challenge arises from annuli that are formed by big bore packers like Gravel Pack Packers, where the annular clearance isextremely small. In cases where open hole completions are run with MPD (Managed Pressure Drilling), the well typically would be displaced to heavier weight fluids before the packer is set and MPD is isolated. This paper illustrates the complications and limitations for estimating friction loss due to the narrow annuli when using drilling hydraulic programs.
Accurate estimation of hydraulic friction loss is extremely essential when using MPD system to maintain BHP(bottomhole pressure) while drilling, tripping, cementing etc. While drilling, the hydraulic models would typically be calibrated to PWD (pressure while drilling) in the BHA (bottomhole assembly), but when running liners, casings or completion systems, the lack of PWD complicates hydraulics and friction loss estimations. This phenomenon is accentuated when displacing the well from lighter drilling fluids to heaviercompletion fluids,especially when the completion fluid reaches the narrow annuli and displays sudden increase in frictional loss value due to the hydraulic model limitations.
This paper focuses on the limitations of estimating the frictional loss in narrow annulus created by the Gravel Pack Packers,when predicted using the drillinghydraulicmodels, and proposes a solution for mitigating such anomalies in calculations. To assess the sudden changes in the pressure loss estimations, the paper further utilizes CFD (Computational Fluid Dynamics) and the frictional loss estimations in these narrow annuli. As an outcome of the study, the paper proposes unique solutions to estimate the frictional pressure loss due to narrow annuli.
A new LWD ultrasonic imager for use in both water- and oil-based muds uses acoustic impedance contrast and ultrasonic amplitude measurements to obtain high-resolution structural, stratigraphic and borehole geometry information. Following extensive testing in the Middle East and the US, this paper presents results from the first European deployment of the new 4.75-in. high-resolution ultrasonic imaging tool.
An ultrasonic transducer, which operates at high frequency, scans the borehole at a high sampling rate to provide detailed measurements of amplitude and traveltime. A borehole caliper measurement is made, based on the time of arrival of the first reflection from the borehole wall. A second measurement detects formation features and tectonic stress indicators from the change in signal amplitude. The amplitude of the reflected wave is a function of the acoustic impedance of the medium. Resulting impedance maps have sufficient resolution to detect sinusoidal, non-sinusoidal and discontinuous features on the borehole wall.
Breakouts, drilling-induced fractures, and tensile zones were used for stress direction determination. Breakout identification was obtained both from amplitude images and oriented potato plot cross sections derived from traveltime measurements.
The orientation of natural fractures is parallel at the maximum stress direction, indicated by drilling-induced fractures and tensile zones. The World Stress Map confirms the maximum stress direction determination.
It was also possible to detect certain key-seat zones and investigate borehole conditions to prevent issues during the subsequent casing job.
The new LWD ultrasonic imaging technique represents an important alternative to density and water-based mud resistivity imaging, which has several limitations. Unlike the resistive imaging LWD tool that is very sensitive to standoff, the higher tolerance of the ultrasonic imaging tool enables the amplitude and traveltime ultrasonic images to contain fewer unwanted artifacts.