Empirical Design of Optimum Frequency of Well Testing for Deepwater Operation

2021 ◽  
Author(s):  
Emmanuel Udofia
Keyword(s):  
Real Time ◽  
Flow Line ◽  
Gas Production ◽  
Health Check ◽  
Well Testing ◽  
Production Volume ◽  
Well Test ◽  
Production Flow ◽  
Test Volume ◽  
Test Execution

Abstract Well testing could be described as a process required to calculate the volumes of (oil, water and gas) production from a well in a bid to identify the current state of the well. Amongst other things, well testing aims to provide information for effective Well, Reservoir and Facility Management. Normally, as a means of well performance health-check, reconciliation factor (RF) is generated by comparing the fiscal production volume against the theoretical well test volume. Experiences from the Coronavirus pandemic has brought about the new normal into well test execution. In deepwater environment, the process of well testing is more challenging and this paper aims to address these challenges and propose optimum well test frequency for deepwater operations. It is usually required that routine well test be conducted once every month on all flowing strings, this is for statutory compliance and well health-check purposes. However, in deepwater environment, it is difficult to comply with this periodic well test requirement mainly due to production flow line slugging, plant process upset and/or tripping resulting in production deferment and operational risk exposure. Furthermore, to carry out well test in deepwater operation, production cutback is required for flow assurance purpose and this usually results in huge production deferment. In this field of interest, this challenge has been managed by deploying a data-driven application to monitor production on individual flowing strings in real-time thereby optimizing the frequency of well test on every flowing well. Varying rate well test data are captured and used to calibrate this tool or application for subsequent real-time production monitoring. This initiative ensures that all the challenges earlier mentioned are managed while actually optimizing the frequency of testing the wells using intelligent application which serves as a ‘virtual meter’ for testing all producing wells in real time. As mentioned, well testing in most deepwater assets remain a big challenge but this project based field experience has ensured effective well testing operation resulting in reduction of production deferment and safety exposure during plant tripping whilst optimizing frequency of testing the wells. Following this achievement of the optimized well test to quarterly frequency in this field in Nigerian deepwater, recommendation from this paper will assist other deepwater field operators in managing routine well testing operation optimally.

A Back Allocation Methodology to Estimate the Real-Time Flow and Assist Production Monitoring

2021 ◽  
Author(s):  
Gabriela Chaves ◽  
Danielle Monteiro ◽  
Virgilio José Martins Ferreira
Keyword(s):  
Real Time ◽  
Input Data ◽  
Oil Field ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Time Flow ◽  
Well Model ◽  
Operational Information ◽  
The Individual

Abstract Commingle production nodes are standard practice in the industry to combine multiple segments into one. This practice is adopted at the subsurface or surface to reduce costs, elements (e.g. pipes), and space. However, it leads to one problem: determine the rates of the single elements. This problem is recurrently solved in the platform scenario using the back allocation approach, where the total platform flowrate is used to obtain the individual wells’ flowrates. The wells’ flowrates are crucial to monitor, manage and make operational decisions in order to optimize field production. This work combined outflow (well and flowline) simulation, reservoir inflow, algorithms, and an optimization problem to calculate the wells’ flowrates and give a status about the current well state. Wells stated as unsuited indicates either the input data, the well model, or the well is behaving not as expected. The well status is valuable operational information that can be interpreted, for instance, to indicate the need for a new well testing, or as reliability rate for simulations run. The well flowrates are calculated considering three scenarios the probable, minimum and maximum. Real-time data is used as input data and production well test is used to tune and update well model and parameters routinely. The methodology was applied using a representative offshore oil field with 14 producing wells for two-years production time. The back allocation methodology showed robustness in all cases, labeling the wells properly, calculating the flowrates, and honoring the platform flowrate.

A Novel Well Test Data Analyzer and Process Optimizer Using Artificial Intelligence and Machine Learning Techniques

2021 ◽  
Author(s):  
Nagaraju Reddicharla ◽  
Subba Ramarao Rachapudi ◽  
Indra Utama ◽  
Furqan Ahmed Khan ◽  
Prabhker Reddy Vanam ◽  
...  
Keyword(s):  
Artificial Intelligence ◽  
Machine Learning ◽  
Real Time ◽  
Test Data ◽  
Oil Field ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Real Time Data ◽  
Well Tests

Abstract Well testing is one of the vital process as part of reservoir performance monitoring. As field matures with increase in number of well stock, testing becomes tedious job in terms of resources (MPFM and test separators) and this affect the production quota delivery. In addition, the test data validation and approval follow a business process that needs up to 10 days before to accept or reject the well tests. The volume of well tests conducted were almost 10,000 and out of them around 10 To 15 % of tests were rejected statistically per year. The objective of the paper is to develop a methodology to reduce well test rejections and timely raising the flag for operator intervention to recommence the well test. This case study was applied in a mature field, which is producing for 40 years that has good volume of historical well test data is available. This paper discusses the development of a data driven Well test data analyzer and Optimizer supported by artificial intelligence (AI) for wells being tested using MPFM in two staged approach. The motivating idea is to ingest historical, real-time data, well model performance curve and prescribe the quality of the well test data to provide flag to operator on real time. The ML prediction results helps testing operations and can reduce the test acceptance turnaround timing drastically from 10 days to hours. In Second layer, an unsupervised model with historical data is helping to identify the parameters that affecting for rejection of the well test example duration of testing, choke size, GOR etc. The outcome from the modeling will be incorporated in updating the well test procedure and testing Philosophy. This approach is being under evaluation stage in one of the asset in ADNOC Onshore. The results are expected to be reducing the well test rejection by at least 5 % that further optimize the resources required and improve the back allocation process. Furthermore, real time flagging of the test Quality will help in reduction of validation cycle from 10 days hours to improve the well testing cycle process. This methodology improves integrated reservoir management compliance of well testing requirements in asset where resources are limited. This methodology is envisioned to be integrated with full field digital oil field Implementation. This is a novel approach to apply machine learning and artificial intelligence application to well testing. It maximizes the utilization of real-time data for creating advisory system that improve test data quality monitoring and timely decision-making to reduce the well test rejection.

Fully Automated and Wirelessly Enabled Drillstem Tests: Seven-Zones Campaign Case Study in Sakhalin

2021 ◽  
Author(s):  
Elias Temer ◽  
Deiveindran Subramaniam
Keyword(s):  
Data Acquisition ◽  
Real Time ◽  
Time Window ◽  
Weather Conditions ◽  
Testing Time ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Operations Control ◽  
Bad Weather

Abstract Well test is one of the crucial steps required to forecast production investments of their fields. However, the operators face many challenges such as reduced capex, exploration budgets, and bad weather conditions that limit the well testing time window. To overcome these challenges, an automated well testing platform enabled a real time monitoring and controlling more zones in a single run for appraisal wells in the Sea of Okhotsk, Russia. This article highlights the test objectives, the job planning, and automated execution of wirelessly enabled operations in very hostile conditions and limited time period. The use of a telemetry system to well test seven zones allowed real-time data acquisition, control of critical downhole equipment, data transmission to the operator's office in town. Various operational cases will be discussed to demonstrate how automated data acquisition and downhole operations control has optimized operations for both the service company and the operator.

Bringing Flexibility and Automation to Well Testing Operations Through Wireless Telemetry - Case Study

2021 ◽  
Author(s):  
Elias Temer ◽  
Deiveindran Subramaniam ◽  
Yermek Kaipov ◽  
Carlos Merino ◽  
Vladimirovich Latvin ◽  
...  
Keyword(s):  
Real Time ◽  
Reservoir Characterization ◽  
Time Window ◽  
Weather Conditions ◽  
Development Planning ◽  
Testing Time ◽  
Well Testing ◽  
Well Test ◽  
Real Time Control ◽  
Field Development

Abstract Dynamic reservoir data are a key driver for operators to meet the forecasted production investments of their fields. However, many challenges during well testing, such as reduced exploration and capex budgets, complex geologic structures, and inclement weather conditions that reduce the well testing time window can prevent them from gathering critical reservoir characterization data needed to make more informed field development planning decisions. To overcome these challenges, a live, downhole reservoir testing platform enabled the most representative reservoir information in real time and connected more zones of interest in a single run for appraisal wells in the Sea of Okhotsk, Russia. This paper describes the test requirements, the prejob planning, and automated execution of wirelessly enabled operations that led to the successful completion of the well test campaign in very hostile conditions, a remote area, and restricted period. The use of a telemetry system to well testing in seven zones enabled real-time control of critical downhole equipment and acquired data at surface, which in turn was transmitted to the operator's office in town in real time. Various operation examples will be discussed to demonstrate how automated data acquisition and downhole operations control has been used to optimize operations by both the service company and the operator.

A Methodology that Enables Real Time Large Volume Reservoir Testing for Deeper Reservoir Targets in Old Wells Without Damaging the Existing Upper Reservoir Layers

2021 ◽  
Author(s):  
Ozgur Karacali ◽  
Sofiane Bellabiod ◽  
Bertrand Theuveny
Keyword(s):  
Real Time ◽  
Hydraulic Pressure ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Noise Sources ◽  
Drilling Rig ◽  
Network Connection ◽  
Execution Phase ◽  
Downhole Measurements

Abstract Pressure transient testing has been significantly revamped and various types have been applied for numerous motives over the past decades. In this paper, a methodology and adapted technology have been discussed in detail for enabling downhole testing operations with existing open perforations above the test packer. This methodology enabled successful downhole testing operations where conventional annulus hydraulic pressure pulse system was ruled out for numerous reasons, such as existence of perforated zones above zone of interest and/or well integrity constraints. The proposed method is based on an acoustic, wireless, bi-directional downhole to surface communication telemetry system. The process utilizes acoustic signals to control downhole tools and transmits downhole measurements in real time through a secured network connection. The procedure used in this well testing methodology is proven successful in numerous well test operations for exploration and appraisal wells in Algeria. The continuously unfolding downhole data has enabled end users and stake holders to take actions and decisions that maximized the value gain while optimizing the test durations and drilling rig utilizations. The successful application of this proposed methodology has enabled parameter estimation during the execution phase of the well testing operations. Data measured in real time is coupled with reservoir engineering interpretation to ensure meaningful sub-surface evaluation. Wellbore dynamics and several other inherent noise sources have been successfully identified to avoid snags of misinterpretation. Wells needing stimulation treatment or longer clean-up durations to enhance the well to reservoir communication quality have been handily identified in real time. The methodology has proven hydrocarbon existence in unexplored layers while enabling incorporation of additional test objectives with further assessments of zones of interest. Real time data greatly reduced uncertainties in well behavior and assisted in informed-decision-making process to adapt well test programs in real time. All well testing objectives were achieved by addressing various challenges that are inherent to conventional memory mode downhole testing operations. The methodology presented will enable the downhole testing operations through drill stem testing (DST) in complex wellbore geometries where conventional well testing approaches were rendered unattainable. The proposed solutions will warrant downhole testing of previously un-appraised formation layers that are overlain by perforated producing reservoirs. The methodology is described in detail and systematically so that the procedure and learnings from Algerian hydrocarbon producing basins can be adapted and applied to other well tests elsewhere around the globe.

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

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 3250-3264 ◽  
Author(s):  
Jianbo Zhang ◽  
Zhiyuan Wang ◽  
Wenguang Duan ◽  
Weiqi Fu ◽  
Baojiang Sun ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Real Time ◽  
Hydrate Formation ◽  
Dynamic Effect ◽  
Time Estimation ◽  
Gas Production ◽  
Well Testing ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Real Time Estimation

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.

scholarly journals Analysis of impact load on tubing and shock absorption during perforating

Open Physics ◽  
2019 ◽  
Vol 17 (1) ◽  
pp. 214-221 ◽  
Author(s):  
Qiao Deng ◽  
Hui Zhang ◽  
Jun Li ◽  
Xuejun Hou ◽  
Hao Wang
Keyword(s):  
Oil And Gas ◽  
Impact Load ◽  
Influence Factors ◽  
Gas Production ◽  
Three Dimensions ◽  
Well Testing ◽  
Well Test ◽  
Shock Absorption ◽  
Oil And Gas Production ◽  
Novel Method

Abstract During the past few decades, the technologies of the higher-shot densities, larger perforating guns and tubing-conveyed perforation (TCP) combined well testing have been used widely used for well completions. This results in a large increase of impact loads in the tubing during TCP. The safety of the tubing is directly related to the success of perforation combined well test,which is the key link in the oil and gas production. In this study, the influence factors of perforating impact load have firstly been analyzed. Also the dynamic response of tubing during TCP in three dimensions has been studied by numerical simulation. According to the computing results, the vulnerable parts of tubing during TCP have been found, where the axial impact load is the strongest and it is concluded that the axial shock absorber has the optimal installation position to achieve the best shock absorption effect, which is verified by the case. This study proposes a novel method for the safety analysis of the tubing, which has important significance to provide guidance for the design of field perforating operations and to improve security.

scholarly journals IMPROVEMENT OF EXPRESS METHOD OF HYDRODYNAMIC WELL TESTING IN THE CONDITIONS OF OIL AND GAS FIELDS OF OIL AND GAS PRODUCTION DEPARTMENT «YAMASHNEFT»

2017 ◽  
pp. 41-47
Author(s):  
E. A. Andaeva ◽  
A. V. Lysenkov ◽  
M. T. Khannanov
Keyword(s):  
Real Time ◽  
Oil And Gas ◽  
Pressure Change ◽  
Gas Production ◽  
Well Testing ◽  
Express Method ◽  
Oil And Gas Production ◽  
Oil And Gas Fields ◽  
Gas Fields ◽  
Technical Measures

To increase the efficiency of hydrodynamic well testing after the geological and technical measures, it is proposed to record the pressure change at the bottom of the well during the development by means of the GIC. Such a solution will allow to combine the process of well development after the IPF with the study, thereby increasing the control over the success of the repairs carried out without additional downtime in real time.

Bringing New Levels of Automation and Flexibility to Well Testing Operations — Case Study

2021 ◽  
Author(s):  
Elias Temer ◽  
Nahomi Zerpa Mendez ◽  
Yermek Kaipov
Keyword(s):  
Data Quality ◽  
Data Acquisition ◽  
Real Time ◽  
Telemetry System ◽  
Well Testing ◽  
Well Test ◽  
Real Time Monitoring ◽  
Test Program ◽  
Wireless Telemetry ◽  
Operations Control

Abstract The oil industry has been perpetually examining well testing methods, with the goal of improving overall efficiency, ensuring data quality, and streamlining processes to achieve program objectives. Over the years, the aim of drillstem testing (DST) has remained mostly unchanged. However, operators want to meet the forecasted production investments of their fields, while improving operational efficiency and maintaining the highest level of operational standards, with safety and the environment being paramount. One of the solutions was developing a live, downhole, reservoir testing platform. The breakthrough consisted in introducing automation and real time monitoring to adjust the test program according to the actual reservoir response rather than blindly following a predefined test program, necessitating better operational flexibility. This platform is united by a wireless telemetry technology allowing an acoustic communication with downhole tools in real time. The automation of the data acquisition, downhole tools actuation and real time monitoring of the downhole operations, gives the operators the ability to perform well tests with reduced uncertainties, less human intervention and improved data quality. The early availability of reservoir knowledge enables operational efficiencies by meeting the test objectives earlier, thus reducing significantly the overall test period and the associated well testing costs. This paper describes the common well test objectives and challenges, the overall design of the wireless telemetry system, and automation of the job preparation and execution of the downhole operations that led to the successful completion of the well test campaign in very hostile condition, remote areas and restricted period. The use of the telemetry system in several well testing campaigns in different regions of the world, allowed to control critical downhole equipment and to acquire reservoir data transmittable to the clients office in town in real time. Various operation examples will be discussed to demonstrate how the automated data acquisition and downhole operations control has been used to optimize operations.

Real-Time Evaluation of Carbon Dioxide Production and Sequestration in a Gas Field

2013 ◽  
Vol 16 (02) ◽  
pp. 134-143 ◽  
Author(s):  
M.. Aschehoug ◽  
C.S.. S. Kabir
Keyword(s):  
Carbon Dioxide ◽  
Real Time ◽  
Material Balance ◽  
Economic Incentives ◽  
Gas Production ◽  
Productivity Index ◽  
Production Volume ◽  
Saline Aquifer ◽  
Time Data ◽  
Gas Field

Summary The production of a substantial fraction of carbon dioxide (CO2) in any hydrocarbon-gas stream poses a significant challenge in terms of separation and sequestration. Both environmental concerns and economic incentives encourage the operators to search for safe, cost-effective ways of disposing of CO2. This paper presents a case study in which a pragmatic solution of CO2 separation at surface and its disposal in a saline aquifer occur in close proximity to its source. A suite of both modern and classical analytical tools is used to understand the production behavior of individual wells. This understanding is imperative because production volume is dictated by the ability to dispose of the associated CO2 volumes to honor the fault-activation pressure limit. The analytical tool kit—transient-productivity index (PI), combined static and dynamic material-balance (MB) methods, and rate-transient analysis (RTA), among others—allowed for the rapid assessment of both the producing gas reservoir and the saline aquifer receiving the CO2 stream. The use of real-time data allowed a comprehensive assessment of in-place volumes for the source gas and the capacity of the aquifer. The injection of supercritical CO2 suggests that the terminal aquifer pressure has been reached by encountering less-than-expected storage volume and by the lowering of fracture-pressure gradient. On-time learning has allowed the asset team to search for alternative CO2-disposal solutions to ensure continuous gas production from this field.

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