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Collaborating Authors
Results
Abstract This paper will describe how fiber optics can be introduced into wells at very low cost, for the purposes of Distributed Temperature Sensing (DTS), using a novel disposable deployment method. It was identified that the cost and risk associated with existing methods of installing fiber optics have. severely restricted the application of downhole distributing fiber-optic sensing. It’s because of this that technology has been developed that is cost effective enough to run in any well, resulting in a disposable system that uses the required materials to perform a singular operation. The system utilises bare fiber optics, located in the tool, referred to as ‘dart’ herein. The fiber optic is de-spooled during free-fall deployment into the well. The system is disposed of in the well following the distributed sensing operation, which would typically only last several hours. Tests performed in a shallow test well have shown that bare fiber optic can be successfully and reliably deployed into the well and that a Distributed Acoustic Sensing (DAS) survey can be performed on each fiber installed. It was observed that the bare fiber was paid out into the well with no detectable slack, resulting in good depth correlation, important for determining the location of any event. It was also observed that the bare fiber attached itself to the inside of the tubing, which is thought to provide a good acoustic coupling - as well as a certain level of protection versus a freely moving fiber in the well. It was concluded that the novel system is viable for use in oil and gas wells and would provide significant cost and risk reductions compared to existing methods of fiber deployment. The resulting increase in data from the application of such a system would have a considerable impact on production and well integrity, as well as offer vast cost savings in well abandonment operations.
- Geophysics > Borehole Geophysics (0.46)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.35)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Optical Fibre Enabled Slickline; Enhancing the Quality of Decision Making through Intelligent Real Time Surveillance Using Distributed Acoustic Sensing and Distributed Temperature Sensing
Berry, Stuart (Paradigm Intervention Technologies Ltd) | Cooper, Gavin (Fairfield Energy Ltd) | Webster, Michael (Production Petrophysics Ltd) | Gysen, Alain (Interpretative Software Products Ltd)
Abstract A fibre enabled slickline system is presented which is capable of performing Distributed Acoustic and Temperature surveys. A case study will be included to demonstrate the performance and value of the service. The fibre enabled slickline system utilizes conventional winch and pressure control equipment to allow deployment into the well, thus leveraging existing field infrastructure and personnel. The provision of an easily transportable drum of fibre enabled slickline along with surface optical interrogation units makes this form simple and cost effective to run. Deploying fibre enabled slickline in the well allows for the real time monitoring of acoustic and temperature changes within the well over its entire length thus providing a start depth, end depth, velocity, direction, frequency and periodicity of downhole events. This in conjunction with controlled manipulation of tubing and annular pressures has proven to be useful in well integrity diagnostics. A case example is presented in this paper using fibre enabled slickline on a North Sea facility to help identify fluid flow behind casing. This data set was gathered while altering the annulus conditions real time and integrating the data with memory temperature and pressure to enhance the interpretation. The novelty of the service is to facilitate the acquisition of distributed survey data combined with the low cost and efficiencies of slickline deployment. Fibre enabled slickline can be used for many applications within the industry making the technique applicable to a wide population of wells.
- North America > United States (0.46)
- Europe > United Kingdom > North Sea (0.25)
- Europe > Norway > North Sea (0.25)
- (2 more...)
Downhole Sand Ingress Detection Using Fibre-Optic Distributed Acoustic Sensors
Thiruvenkatanathan, Pradyumna (BP) | Langnes, Tommy (BP) | Beaumont, Paul (BP) | White, Daniel (BP) | Webster, Michael (BP)
Abstract Sand production remains a key technical challenge in many reservoirs where formations comprise of weakly consolidated sandstone. Sand control completion equipment is typically installed to prevent sand from entering the well. However, in cases where the sand control is ineffective due to installation flaws/defects, high sand production may occur often requiring choking back of wells and resulting in significant hydrocarbon production losses. An effective remediation requires identification of locations of sand entry. However, there is currently no proven technology available in the market that accurately identifies downhole sand ingress locations in real-time. In this paper, we present results from a new technology solution that addresses this challenge by using in-well conveyed fibre optic distributed acoustic sensors (DAS) for the detection of sand ingress zones across the reservoir section throughout the production period in real time. The technology employs a novel signal processing technique that isolates and extracts acoustic signals resulting from sand ingress from background flow and instrumentation noise in real time. The new processing architecture also addresses the "big-data problem" that currently hinders DAS technology uptake through use of intelligent feature-extraction techniques that reduce data volumes at source (by several orders of magnitude). The technology feasibility has now been verified both through flow loop experiments and through multiple field trials and has been successfully used to inform the first targeted sand remediation in a BP production well.
- Well Completion > Sand Control (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Solids (scale, sand, etc.) (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract Measured temperature behaviour over the reservoir section in a production or injection well is influenced by various factors, including reservoir presence, reservoir quality, completion architecture and fluid flow profile. In the producing section of a well, temperature is dominated by effects resulting from flow, and the relative proportion of the fluid phases. This temperature can be used to estimate a production profile including the relative amount of fluid produced at each interval. Oil, gas and water fluid phases have different thermal properties and in a controlled environments, the temperature can help define the proportion of each phase being produced. In conventional production logging, tool strings include a temperature sensor. Temperature can also be obtained by deploying optical DTS (Distributed Temperature Sensing) in the well. This paper discusses some of the parameters that control temperature behaviour in producing wells. How sensitive the temperature is relative to these parameters and how unique that production profile is when back-calculated from temperature data. A robust flow profile was build using conventional production logging data using the temperature as an additional constraint. A series of flow scenarios were identified with production logs from offset wells and used in sensitivity analysis modelling. This was the basis for a feasibility study for DTS deployment. Several cases were found where the temperature profile was identical to a chosen base case temperature, for very different inflow scenarios. These different scenarios were significant enough to impact well remediation or reservoir management decisions. This paper presents the critical parameters used in DTS profile analysis and the associated uncertainty for this environment. The addition of qualitative DAS (Distributed Acoustic Sensing) data will be demonstrated as a key input to help constraint the possible scenarios and achieve a more unique solution.
- Europe > United Kingdom (0.28)
- Asia > Middle East (0.28)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.48)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/9 > Clair Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/8 > Clair Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/7 > Clair Field (0.99)
- (4 more...)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
New Sensor Development Helps Optimize Production Logging Data Acquisition In Horizontal Wells
Zett, Adrian (BP) | Webster, Michael (BP) | Noordermeer, Alwin (BP) | Hockley, Mitchell (GE Oilfield Technology) | Lockyer, Glynn (GE Oilfield Technology) | Browne, Hugh (GE Oilfield Technology) | Donkin, Charles (GE Oilfield Technology)
ABSTRACT As horizontal wells become increasingly common, the need to make measurements to optimize well health and manage the reservoir also increases. Production logging in horizontal wells with multiphase flow presents data acquisition challenges in the form of conveyance method and sensor selection. In this paper we present an approach to logging a horizontal well using new generation array sensors. The well was cased and perforated with high water cut and sand production. Logging while tractoring a combination of conventional (centralized) and array sensors provided a good quality data set that enabled successful identification and shut-off of sand and water. The use of a new impeller design in a mini-spinner array helped overcome the challenges sand production posed in the well. Smaller mini-spinner thresholds improved the velocity profile, allowing us to identify water recirculation at very low rates. An array resistance measurement provided an estimate of water holdup. Tool rotation proved an important benefit for array sensors run in this harsh environment. Tool rotation helped keep the sensors free from debris while the traditional centralised spinner showed an increased tendency for jamming when intersecting sand accumulations in casing troughs or restrictions along the well trajectory. In addition, the rotating array sensors provide good circumferential coverage in the well. A sand detection instrument was used in combination with the production logging string. The instrument is combinable with the production logging string and simultaneous data acquisition permits to integrate all sensors, allowing a robust interpretation of sand influx and water salinity. This paper focuses on the acquisition of new generation array data to help meet the well intervention objectives leading to a commercial and technically successful out-come. It identifies the strengths and gaps of current technology relative to existing challenges in horizontal wells and the need to move to array measurements.
- Europe (1.00)
- North America > United States (0.93)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/16a > Eastern Trough Area Project > Mungo Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/20 > Eastern Trough Area Project > Mungo Field (0.99)
- North America > Canada > Alberta > Howard Field > Bpc Et Al Howard 6-31-79-5 Well (0.89)
- (4 more...)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
New Sensor Development Helps Optimise Production Logging Data Acquisition In Horizontal Wells
Zett, Adrian (BP) | Webster, Michael (BP) | Noordermeer, Alwin (BP) | Hockley, Mitchell (GE Oilfield Technology) | Lockyer, Glynn (GE Oilfield Technology) | Browne, Hugh (GE Oilfield Technology) | Donkin, Charles (GE Oilfield Technology)
ABSTRACT: As horizontal wells become increasingly common, the need to make measurements to optimise well health and manage the reservoir also increases. Production logging in horizontal wells with multiphase flow present data acquisition challenges in the form of both conveyance method and sensor selection. In this paper we present an approach to logging a horizontal well using new generation array sensors. The well was cased and perforated with high water cut and sand production. Logging while tractoring a combination of conventional (centralised) and array sensors provided a good quality data set that enabled successful identification and shut off of sand and water. The use of a new impeller design in a minispinner array helped overcome the challenges sand production posed in the well. Smaller minispinner thresholds improved the velocity profile allowing us to identify water recirculation at very low rates. An array resistance measurement provided an estimate of water holdup. Tool rotation proved a tremendous benefit for array sensors run in this harsh environment. Tool rotation helped keep the sensors free from debris while the traditional centralised spinner show an increased tendency for jamming when intersecting sand dunes or restrictions along the well trajectory. In addition, the rotating array sensors provide better circumferential coverage in the well. A sand detection instrument was used in combination with the production logging string. The instrument is fully combinable with the production logging string and simultaneous data acquisition makes it easy to integrate all sensors allowing a robust interpretation of sand influx and water salinity. INTRODUCTION The candidate well is located on Mungo Field (Central North Sea, Zett et al 2008) and was completed as a gaslift producer in September 2009. At the time of logging (August 2010), the well was tested with 671bopd, 1173bwpd and 0.27mmscf/d produced gas.
- Europe > North Sea (0.54)
- North America > United States (0.46)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/16a > Eastern Trough Area Project > Mungo Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/20 > Eastern Trough Area Project > Mungo Field (0.99)
- Europe > Norway > North Sea (0.89)
- (2 more...)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Providing Accurate Pl Interpretation With Multi-Probe, Multi-Sensor Tools In Segregated Flow Environments
Frisch, Gary (Halliburton Energy Services) | Jung, Marshall (Halliburton Energy Services) | Alldredge, Paul (Halliburton Energy Services) | Zett, Adrian (BP Exploration and Production) | Webster, Michael (BP Exploration and Production)
The newest production logging tools have multiple sensors that can provide valuable information concerning fluid types, fluid compositions, and fluid velocities, particularly in segregated flow environments. Since these tools include a relative bearing sensor, it is possible to determine where each sensor is located in the wellbore and flow stream. The interpretation of multiple sensors in a continuously changing wellbore environment required the development of software that combines navigational information about the location of the sensors in the flow stream, as well as data from the sensors relating to velocity and phase changes. The Capacitance Array Tool (CAT) and the Resistivity Array Tool (RAT) provide detailed information regarding the wellbore fluids either consisting of gas, oil, and water or combination. It is possible to distinguish the segregation of the phases from the tool orientation and sensor physics. The Spinner Array Tool (SAT) provides velocity information from the six spinners, which are equally distributed around the wellbore. The combination of the 12 CAT and RAT readings with the six spinner readings required new processing to provide the necessary interpretation of these new array production logging measurements. Since the production logging tool string can rotate in the wellbore, differences in each sensors measurement between logging passes may be the combined effects of the sensor being in a different azimuthal orientation, changes in flow regime, or holdup. New analysis methods have been developed to provide integrated interpretations of these new multi-probe sensors. New log presentations were developed to help display the segregated fluid profiles encountered that were previously ignored by the standard PL logging tools and processing. Several examples of deviated and horizontal wellbores with two- and three-phase flows are presented and discussed. INTRODUCTION Traditional production logging tools with single sensors may not provide the most accurate answer in highly deviated and horizontal wellbores. These traditional PL sensors are usually center sample tools or have single point measurements for properties, such as velocity, phase components, temperature, and pressure. Phase segregation occurs in many wells, even including those with little deviation from vertical; the lighter phases migrate to the high side of the well, and the heavier phases migrate to the low side. To accurately determine the flow rates from wells in which fluid segregation is expected, several new fullbore measurements tools have been developed to help address issues found with conventional tools. These tools described in this paper will be referred to as Production Array Logs (PAL) to distinguish them from the standard PL logs. Not only do the PAL tools have multiple sensors, these tools also have a relative bearing measurement to determine the position of each sensor in the wellbore. In addition, the SAT tool provides measurement of the wellbore deviation. These new tools also require a new interpretation process that combines the benefits of the newer sensors and addresses problems that the deviated and horizontal wellbores cause in the standard PL interpretation procedures. PAL TOOLS One of the challenges of production logging is to identify the types of fluids and the volumes of each fluid phase along with point of entry into the wellbore.
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Rocky Mountains > Duvernay Formation (0.89)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Rocky Mountains > Duvernay Formation (0.89)
- Europe > United Kingdom > Scotland (0.89)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)