The Transient Dynamics of Permanent Fiber Temperature Analysis and Downhole Gauge Evaluation of an Acid Stimulation Job in a Brown Field, Offshore Malaysia

2021 ◽  
Author(s):  
Chang Siong Ting ◽  
Nur’ain Minggu ◽  
Dahlila Kamat ◽  
Latief Riyanto ◽  
Chee Seong Tan ◽  
...  
Keyword(s):  
Job Evaluation ◽  
Distributed Temperature Sensing ◽  
Reservoir Properties ◽  
Matrix Acidizing ◽  
Potential Formation ◽  
Wellbore Temperature ◽  
Well Trajectory ◽  
Baseline Temperature ◽  
Surface Production ◽  
Gas Lift

Abstract Well B-2 is a dual-string producers with Distributed Temperature Sensing (DTS) fiber installed along the long string (i.e. Well B-2L) across the reservoir sections. Each zone comprises of sub-layers. This system enabled the operator to continuously monitor the wellbore temperature across all the producing intervals including gas-lift monitoring, well integrity identification, zonal inflow profiling and stimulation job evaluation. This paper mainly discusses the post matrix acid stimulation job with interpreted DTS and zonal Permanent Downhole Gauge (PDG) data. Well B-2L has been selected for matrix acidizing treatment to improve the productivity due to potential formation damage, proven by the declining production over the years. Prior to the execution of the acidizing job, several conformance jobs such as injectivity test, tubing pickling were performed. This is followed by the main acid treatment and flow back. DTS & zonal PDG data were acquired throughout the operation. A transient simulator model was built incorporating all the reservoir properties including well trajectory and completion schematic to analyze the DTS profile and understand the zonal inflow profiling for each zone post treatment. A baseline temperature was acquired for the geothermal evaluation. The DTS data has been studied according to actual event schedules. Some significant findings are; i) completion accessories effect (feedthru packers) creates temperature anomalies, ii) leak points detected at top producing zone signifies cooling effect due to injected fluid. The main treatment was intended at zone 2 and 3 using nitrified acid. However, leak points at top zone caused bypassed injection into Zone 1 and 2 instead. Fiber optic DTS warmback profiles post main-treatment was analyzed to quantify the fluid intake from sub-layer in each zone. Qualitatively from the DTS-interpreted zonal profiling, the data clearly shows most of treatment fluid is being injected into Zone 1 and 2 with no intakes at Zone 3. Furthermore, warmback analysis confirmed the high intake zones from sub-layers within the main zone based on the permeability contrast. This paper will further discuss the zonal injectivity understanding for improvement from the zonal-inflow profiling evaluation by incorporating DTS, PDG and surface production data.

Cable Thru Downhole Insert Safety Valve: A New Paradigm

2021 ◽  
Author(s):  
Kuswanto Kuswanto ◽  
Oka Fabian ◽  
Orient B Samuel ◽  
Mohd Yuzmanizeil B Yaakub ◽  
Chua Hing Leong ◽  
...  
Keyword(s):  
Safety Valve ◽  
Cost Effective ◽  
Submersible Pump ◽  
New Paradigm ◽  
Reservoir Properties ◽  
Technology Application ◽  
Artificial Lift ◽  
Water Cut ◽  
The Right ◽  
Gas Lift

Abstract The B Field is located in the South China Sea, about 45 KM offshore Sarawak, Malaysia, in a water depth approximately 230 ft. Its structure is generally regarded as a gentle rollover anticline with collapsed crest resulting from growth faulting. The reservoirs were deposited in a coastal to shallow marine with some channels observed. Multiple stacked reservoirs consist of a series of very thick stacked alternating sandstone and minor shale layers with differing reservoir properties. The shallow zones are unconsolidated, and the wells were completed with internal gravel packs. Wells in B Field mostly were completed in multi-layered reservoirs as dual strings with SSDs and meant to produce as a commingled production. The well BX is located within B Field and designed as oil producer well with a conventional tubing jointedElectrical Submersible Pump (ESP) system which was installed back in 2008. Refer to figure 1, the initial completion schematic is 3-1/2″ single string that consist of the single production packer, gas lift mandrel, tubing retrievable Surface Controlled Subsurface Safety Valve (SCSSV) and ESP. The production packers equipped with the feed thru design to accommodate the ESP cable and the gas vent valve as part of the ESP completion design. The gas lift mandrel was installed in the completion string as a backup artificial lift method to receive the gas lift and orifice valve in the event of the conventional ESP failed. Hence the well still able to produce by introducing the gas thru the annulus to activate the gas lift valve. Eventually throughout the end of the the field life, the well would depend on the ESP system for the primary lifting method due to gas lift depth limitation and the gas supply. The conventional ESP failed after seven years of operation which is above the average ESP lifetime. The well last produced at a flow rate with 28 % water cut, however the well is not at the end of the field life. Based on the economical study with the right technology and cost efficient approach, the well still economicaly profitable. The Thru Tubing (TT) ESP technology is approached as cost effective solution compare to fully well workover. Despite a couple of operational challenges, for example, setting the cable hanger, maintaining downhole barrier requirement, the Thru Tubing Electrical Submersible Pump Cable Deployed (TTESP CD) and Cable Thru Insert Safety Valve (CT-ISV) was successfully installed. Several post-installation findings have uncovered some problems which are requiring some additional technical and operation improvement for future similar applications. This paper will highlight the deployment of the Cable Thru Insert Safety Valve (CT-ISV) that was successfully installed as pilot, which is the first application in the world, and also highlights the success, lesson learnt and improvement for future requirement for the CT-ISV application as one of the solution for retrofitting completion application without jeopardizing the well integrity. This achievement is collaboration between Company and service partner as the technology and deployment under the proprietary scope. Further technology application, the replication of this insert safety valve was conducted and successfully deployed on other three wells.

scholarly journals A Novel Temperature Prediction Model Considering Stress Sensitivity for the Multiphase Fractured Horizontal Well in Tight Reservoirs

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 4760
Author(s):  
Yonggang Duan ◽  
Ruiduo Zhang ◽  
Mingqiang Wei
Keyword(s):  
Prediction Model ◽  
Temperature Profile ◽  
Horizontal Well ◽  
Stress Sensitivity ◽  
Temperature Sensing ◽  
Distributed Temperature Sensing ◽  
Temperature Prediction ◽  
Multi Stage ◽  
Fractured Horizontal Well ◽  
Wellbore Temperature

An accurate temperature profile of the multi-stage fractured horizontal well is the foundation of production profile interpretation using distributed temperature sensing. In this paper, an oil-water two-phase flow multi-stage fractured horizontal well temperature prediction model considering stress sensitivity effect and the Joule–Thomson effect is constructed. Based on the simulation calculation, the wellbore temperature variation under different formation parameters, water cuts, and fracture parameters is discussed. The wellbore temperature distribution in multistage fractured horizontal wells is affected by many factors. According to the principle of orthogonal experimental design, the difference between wellbore temperature and initial formation temperature is selected as the analysis condition. Sixteen groups of orthogonal experimental calculations are designed and conducted. By analyzing the experimental results, it is found that the fracture half-length, water production, and formation permeability are the main controlling factors of the wellbore temperature profile. Finally, the production profile of the well is determined by calculating the temperature profile of a tight oil well and fitting it to the measured data of distributed temperature sensing.

scholarly journals An Automatic Well Planner for Complex Well Trajectories

2021 ◽  
Author(s):  
Brage S. Kristoffersen ◽  
Mathias C. Bellout ◽  
Thiago L. Silva ◽  
Carl F. Berg
Keyword(s):  
Neural Networks ◽  
Differential Evolution ◽  
Computational Cost ◽  
Differential Evolution Algorithm ◽  
Trajectory Design ◽  
Drilling Process ◽  
Data Generation ◽  
Reservoir Properties ◽  
Well Trajectory ◽  
Complex Well

AbstractA data-driven automatic well planner procedure is implemented to develop complex well trajectories by efficiently adapting to near-well reservoir properties and geometry. The procedure draws inspiration from geosteering drilling operations, where modern logging-while-drilling tools enable the adjustment of well trajectories during drilling. Analogously, the proposed procedure develops well trajectories based on a selected geology-based fitness measure using an artificial neural network as the decision maker in a virtual sequential drilling process within a reservoir model. While neural networks have seen extensive use in other areas of reservoir management, to the best of our knowledge, this work is the first to apply neural networks on well trajectory design within reservoir models. Importantly, both the input data generation used to train the network and the actual trajectory design operations conducted by the trained network are efficient calculations, since these rely solely on geometric and initial properties of the reservoir, and thus do not require additional simulations. Therefore, the main advantage over traditional methods is the highly articulated well trajectories adapted to reservoir properties using a low-order well representation. Well trajectories generated in a realistic reservoir by the automatic well planner are qualitatively and quantitatively compared to trajectories generated by a differential evolution algorithm. Results show that the resulting trajectories improve productivity compared to straight line well trajectories, both for channelized and geometrically complex reservoirs. Moreover, the overall productivity with the resulting trajectories is comparable to well solutions obtained using differential evolution, but at a much lower computational cost.

A Real-Time Fiber Optical System for Wellbore Monitoring: A Johan Sverdrup Case Study

2021 ◽  
Author(s):  
Maximilian Georg Schuberth ◽  
Håkon Sunde Bakka ◽  
Claire Emma Birnie ◽  
Stefan Dümmong ◽  
Kjetil Eik Haavik ◽  
...  
Keyword(s):  
Decision Making ◽  
Real Time ◽  
Large Data ◽  
Pipeline Architecture ◽  
Distributed Temperature Sensing ◽  
Time Data ◽  
Data Pipeline ◽  
Start Up ◽  
Custom Made ◽  
Gas Lift

Abstract Fiber Optic (FO) sensing capabilities for downhole monitoring include, among other techniques, Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS). The appeal of DTS and DAS data is based on its high temporal and spatial sampling, allowing for very fine localization of processes in a wellbore. Furthermore, the broad frequency spectrum that especially DAS data is acquired with, enables observations, ranging from more continuous effects like oil flow, to more distinct effects like opening and closing of valves. Due to the high data volume of hundreds of Gb per well per hour, DAS data has traditionally been acquired acquisition-based, where data is recorded for a limited amount of time and processed at a later point in time. This limits the decision-making capability based on this data as reacting to events is only possible long after the event occurred. Equinor has addressed these decision-making shortcomings by building a real-time streaming solution for transferring, processing, and interpretation of its FO data at the Johan Sverdrup field in the North Sea. The streaming solution for FO data consists of offshore interrogators streaming raw DAS and DTS data via a dedicated bandwidth to an onshore processing cluster. There, DAS data is transformed into FO feature data, e.g., Frequency Band Energies, which are heavily decimated versions of the raw data; allowing insight extraction, while significantly reducing data volumes. DTS and DAS FO feature data are then streamed to a custom-made, cloud-based visualization and integration platform. This cloud-based platform allows efficient inspection of large data sets, control and evaluation of applications based on these data, and sharing of FO data within the Johan Sverdrup asset. During the last year, this FO data streaming pipeline has processed several tens of PB of FO data, monitoring a range of well operations and processes. Qualitatively, the benefits and potential of the real-time data acquisitions have been illustrated by providing a greater understanding of current well conditions and processes. Alongside the FO data pipeline, multiple prototype applications have been developed for automated monitoring of Gas Lift Valves, Safety Valve operations, Gas Lift rate estimation, and monitoring production start-up, all providing insights in real-time. For certain use cases, such as monitoring production start-up, the FO data provides a previously non-existent monitoring solution. In this paper, we will discuss in detail the FO data pipeline architecture from-platform-to-cloud, illustrate several data examples, and discuss the way-forward for "real-time" FO data analytics.

Managing the Impact of in Situ Fines Migration in Production Optimization – A Case History from a Niger Delta Field

2021 ◽  
Author(s):  
Tamunomiete Oruambo ◽  
Elias Arochukwu ◽  
Felix Okoro ◽  
Linda Dennar ◽  
Olalekan Otubu
Keyword(s):  
Oil And Gas ◽  
Production Optimization ◽  
Volume Estimation ◽  
Fines Migration ◽  
Matrix Acidizing ◽  
The Right ◽  
The Impact ◽  
Additional Stimulation ◽  
Gas Lift

Abstract In the oil and gas business, a key strategy of well management is the deployment of the right tools and knowledge to enable continuous and optimized production. One of such tools is Matrix acidizing - A stimulation activity designed to remove wellbore damage and improve well inflow. The ability to sustain optimal production from most wells after acidization is often hampered with further fines migration problems and this requires specialized treatment to mitigate. WELL-001 quit production and was re-entered for a workover in 2018, to recomplete shallower on the same reservoir sand and restore production, however, post workover and subsequent clean up, the well failed to sustain flow. Two additional stimulation operations were also unsuccessful despite gas lift assistance. An Integrated review was held which identified key damage mechanisms impeding flow; deep fines migration which are not well handled by conventional stimulation recipes, emulsion and impairment from Loss Circulation Material (CaCO3 + XCD Polymer). A Novel solution was identified which included an Ultra-Thin Tackifying Agent (UTTA) as part of the stimulation cocktail with the primary purpose of stabilizing the fines at source and preventing further migration with the flowing fluids. The treatment was deployed successfully and the well lifted immediately, achieving a rate of 800 bopd vs a planned potential of 650 bopd. The impact of this success is not only evident in production but also in resource volume estimation and booking.

A Simple and Reliable Approach for the Estimation of the Joule-Thomson Coefficient of Reservoir Gas at Bottomhole Conditions

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 960-968 ◽  
Author(s):  
Mario Pinto ◽  
Chaitanya Karale ◽  
Prasanta Das
Keyword(s):  
Experimental Data ◽  
Fluid Flow ◽  
Continuous Monitoring ◽  
Temperature Drop ◽  
Thermal Response ◽  
Distributed Temperature Sensing ◽  
Reliable Prediction ◽  
Wellbore Temperature ◽  
Thomson Coefficient ◽  
Scale Data

Summary With the advent of distributed temperature sensing (DTS), accurate and continuous monitoring of the wellbore-temperature profile is possible, which helps identify fluid flow from each reservoir layer. The reliable prediction of fluid flow during large drawdown requires an accurate value of the Joule-Thomson coefficient (JTC), which is a measure of the change in temperature (T) of a fluid for a given change in pressure (P) at constant enthalpy. The JTC also serves as an input for the interpretation of temperature-log data, which can be used to identify water- or gas-entry locations. Furthermore, an accurate JTC value is important when modeling the thermal response of the reservoir. The equation-of-state (EOS) method can be used to predict the JTC of reservoir gas. However, this might not be an easy task because of the complexity involved. In contrast, a simple and reliable method to evaluate the JTC for reservoir gas is presented. Conditions under which this method is applicable are discussed in detail by referring to a typical phase diagram. In addition, a discretized approach to calculate the temperature change during a throttling process with the JTC is also presented. The methodology has been validated at three levels with experimental data available in the literature—comparison of experimental vs. predicted JTC values of mixtures, comparison of experimentally observed vs. predicted temperature drop for a given pressure drop with laboratory-scale data, and comparison of experimentally observed vs. predicted temperature drop for a given drawdown with actual reservoir data. A good match with experimental data was obtained within all three areas, demonstrating the reliability of the methodology.

Evaluating Alternate Artificial Lift Methods in the Niger Delta

2021 ◽  
Author(s):  
Priscilla Enwere ◽  
Ademola Amusa ◽  
Oluwafemi Olominu ◽  
Nchekwube Lazson ◽  
Emmanuel Mbonu ◽  
...  
Keyword(s):  
Niger Delta ◽  
Selection Criteria ◽  
Selection Criterion ◽  
Network Models ◽  
Submersible Pump ◽  
Artificial Lift ◽  
Electrical Submersible Pump ◽  
Water Cut ◽  
Surface Production ◽  
Gas Lift

Abstract Gas lift is currently being utilized as the artificial lift system in OML Z, this has been so for the last thirty years. Although, the field has seen significant increase in production rates in recent times, gas lift requirement has increased with increase in production and water cut. To maximize production and value from OML Z, it is expedient to seek an alternative artificial lift method that can debottleneck and unlock the potential of fields within OML Z where production has been less than 50% since the field was brought on stream. Production from the gas lifted fields within OML Z is constrained by a combination of bottlenecked gas lift facility and surface production facility. This study explores the different artificial lift methods and selects an applicable technology for OML Z using a developed selection criterion. Electrical Submersible Pump (ESP) found suitable for OML Z is further analyzed for feasibility and application within OML Z given existing limitations. The candidate reservoir and well selection criteria are elaborated upon, taking into consideration several elements that contribute to the production process. The results of the well and network models, that shows the significant gains attributed to the conversion of selected previously gas lifted wells to ESPs, are discussed. The economic benefit of such conversion is also shown.

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