Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
Gupta, Shilpi (Schlumberger) | Pandey, Arun (Schlumberger) | Ogra, Konark (Schlumberger) | Sinha, Ravi (Schlumberger) | Chandra, Yogesh (ONGC) | Singh, PP (ONGC) | Koushik, YD (ONGC) | Verma, Vibhor (Schlumberger) | Chaudhary, Sunil (Oil & Natural Gas Corp. Ltd.)
Production logging has been traditionally used for zonal quantification of layers for identification of most obvious workover for water shut off, acid wash or reperforation candidate identification. The basic sensors help in making some of the critical decisions for immediate gain in oil production or reduction in water cut. However, this technology can be used in a non standard format for various purposes including multilayer testing to obtain layer wise permeability and skin factor using pressure and flow rate transient data acquired with production logging tools. This is very crucial and complements the present wellbore flow phenomenon to better understand relative zonal performance of well at any stage of its production. In addition, production logging along with the pulsed neutron technique is very crucial to evaluate the complete wellbore phenomenon, understand some of the behind the production string fluid flow behaviors. Another major concern in low flow rate wells is recirculation, causing fall back of heavier water phase while lighter phase like oil and gas move upwards. This well bore phenomenon renders the quantification from production logging string, and this in extension also prevents any comprehensive workover decisions on the well because of the risk involved. Oil rate computation from hydrocarbon bubble rates becomes very critical in such scenarios to bring out the most optimal results and enhance confidence in workover decisions. Another key concern in any reservoir is to evaluate the productivity Index; this is even more critical once the field is on production. It is essential to determine the performance of various commingled layers and reform the Injector producer strategy for pressure support or immediate workover. Selective Inflow performance is a technique used to identify the Productivity index of various layers in a commingled situation. This paper elaborates on various non conventional uses of production logging from the western offshore India.
Brown field management has been a key focus in the western offshore region. Over the last decade cased hole production logging for evaluation of reservoir phenomenon has been the backbone of workover operation in western offshore India. Besides the usual operations production logging has been pivotal in determining various important parameters for field development. Various unconventional uses require understanding of the tool physics and limitation. Advanced generation of production logging tools not only provide additional information in terms of wellbore flow fractions, slippage velocities and complex flow regimes but their basic outputs can also be utilized in variety of applications for reservoir evaluation and wellbore flow monitoring. Following sections describe several case studies describing unconventional usage of production logging outcomes.
Unconventional Applications of Production Logging
Case Study 1: Selective Inflow Performance
Field wise production logging has always been an excellent source to evaluate the open hole results and suggest some immediate workover to optimise the production. Selective Inflow performance is new variation in the already existing technique used to identify the Productivity index of various layers in a commingled situation. This operation can provide us with the openhole flow potential of the well and thus help in mapping the flow profile in the reservoir. A multichoke production logging survey usually covering two to three choke sizes is performed and flow profiling for each survey is done.
The success of recent applications in underbalanced drilling (UBD) and managed pressure drilling (MPD) has accelerated the development of technology in order to optimize drilling operations. The increased number of depleted reservoirs and the necessity for reducing formation damage has also increased the need to apply UBD/MPD to such candidate fields. Several methods used the latest mechanistic multiphase flow models in order to predict bottomhole circulation pressure when performing UBD/MPD operations. A new model is developed that utilizes the latest mechanistic multiphase flow models; the developed model calculates the bottomhole circulation pressure as a function of surface injection rates, choke pressure and time.
The developed model can be used in designing and optimizing UBD/MPD operations in terms of determining the correct injection rate and/or choke pressure. In addition, the developed model is used to utilize the reservoir energy to attain correct bottomhole conditions. The developed model in addition to utilizing the latest mechanistic models also reduce the error in calculating the bottom hole pressure by incorporating an algorithm in which the injection rates are calculated in-situ rather than assuming constant injection rates.
The model is validated against data from literature and against a commercial simulator. Results show that the developed algorithm has increased the accuracy in predicting bottomhole pressure by incorporating the changes in new gas and liquid injection rates.
At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
The time taken to safely optimise a reservoir produced by artificial lift can be measured in weeks or months.
Typically the well by well process is as follows:
• Well testing
• Amalgamation of the well test data with down hole gauge and ESP controller data
• Analysis of the data to find the existing operation conditions
• Analysis of the ESP pump curve operating point and optimisation limitations
• Sensitivity studies in software to assess the optimum frequency and WHP
• Notification for the field operations to action the changes
• Further well tests to verify the new production data.
• Analysis of the data to ensure the ESP and well are running optimally and safely at the new set points
New technology enables this process to be performed in real time across the entire reservoir or field, significantly shortening the time to increased production and enabling real time reservoir management.
Each artificially lifted well in the reservoir was equipped with an intelligent data processing device programmed with a real time model of the well. The processors were linked to a central access point where the operation of field could be remotely viewed in real time.
Each well's processor was provided with a target bottom hole flowing pressure to enable the optimum production of the reservoir. The real time system automatically compared the desired target drawdown values with the capability of the pumping system installed in each well, and automatically suggested the optimum operating frequency and well head pressure to achieve the target. Where the lift system was not capable of producing to the target bottom hole pressure, a larger pump was automatically recommended. As production conditions change the system adapted its recommended operating points to compensate and maintain target production.
This paper discusses three case studies where real time optimisation and diagnosis lead to improved production from the reservoir.
In order to develop the design requirement with current regulatory and contemporary HSE practices, for a typical sour oil/gas production facility, a hypothetical case of about 3 mol % v/v H2S in gas and 300 ppm w/w H2S in oil, of multiphase feed stream, has been studied through the dispersion modeling for the conceptual stage. The findings indicated credible downwind lethal / semi lethal threat distance up to 300 meters. The conclusions of the H2S toxic risk assessment combined with the inherent safe design guidelines have yielded an entirely new set of requirement for the risk reduction. To start with it was realized that safe distance control room should be constructed and facilities should be designed for the remote operation, utilizing the new trends of foundation field bus, electronic marshaling and SIL-3 fiber optic sensors. The facility should be access controlled with mandatory PPE requirement of personal H2S monitors and personal quick donning (5 sec) escape SCABA (15 minutes capacity). The centrifugal compressors should be new generation design of enclosed and hermetically sealed type, levitated with magnetic bearing, without dry gas seals and oil lubrication. The vessels should be ASME Section VIII "lethal service?? design and plant piping should be as per fluid category "M?? of ASME B31.3 chapter VIII. Furthermore, stress relieving for thicknesses as low as 10 mm, rather than ASME B31.3 code specified >19 mm would be required. Small valves <4?? sizes should be of forged steel instead of cast steel. The export oil/gas pipelines and flow lines should be designed for =< 50~60 % of SMYS. Plate instead of Shell and Tube Exchangers. Adequate margins between vessels design and operating pressures to avoid PSV chattering. The PSV's to have acoustic monitoring. The facilities should be designed free of valve pits and internal corrosion monitoring pits.
Saudi Arabian non associate gas reservoirs produce various amounts of condensate depending upon field and reservoir. In most cases, these wells are hydraulically fractured and at the initial stage after such stimulation treatment, each well needs to unload high quantity of the pumped fluid to ensure full potential. If the liquid starts accumulating in the wellbore during production, the well productivity will gradually decrease and eventually may stop producing. If the gas flow velocity in the production string is high enough, the gas will continue flowing and will carry the liquid droplets up the wellbore to the surface. The minimum velocity and critical gas rate (Qcrit) are therefore the determining factors while producing a well or several wells from a condensate-rich field so as to ensure the stable field production rate and maintain production plateau.
An analytical model has been developed to iteratively compute the critical velocity (Vcrit) and Qcrit, for given flowing wellhead pressure (FWHP), tubing diameter, and many other reservoir and completion properties. If the FWHP is set and a certain production rate is expected of a well, the program automatically computes the pressure drop due to friction, dynamic hydrostatic head, and the bottomhole pressure. Simultaneously, both Vcrit and Qcrit to unload the fluids are calculated. If the Qcrit is above the expected production rate, a different wellbore completion is automatically selected and computation is continued until Qcrit is lower than the expected rate of the well. If this is not possible, the program will display appropriate message.
Several wells from a condensate gas reservoir are analyzed from a field that has to maintain certain production potential for a given number of years. The analyses show that the wells that are producing without intervention are those that are confirmed by this model to be flowing above the Qcrit. For wells that were intermittently producing and ultimately could not sustain production were producing at rates below the critical values. Using this iterative model, those rates are automatically adjusted or new completion string is suggested to bring them back into production.
Significant advances have been made in formation testing since the introduction of wireline pumpout testers (WLPT), particularly with respect to downhole fluid compositional measurements. Optical sensors and the use of spectroscopic methods have been developed to improve sample quality and minimize sampling time in downhole environments. As a laboratory technique, spectroscopy is a ubiquitous and powerful technology that has been used worldwide for decades to measure the physical and chemical properties of many materials, including petroleum, geological, and hydrological samples. However, laboratory-grade, high-resolution spectrometers are incompatible with the hostile environments encountered downhole, at wellheads, and on pipelines. Only limited resolution techniques are available for the rugged conditions of the oil field. This paper introduces a new optical technology that can provide high-resolution, laboratory-quality analyses in harsh oilfield environments.
A new technology for optical sensing, multivariate optical computing (MOC), has been developed and is a non-spectroscopic technique. This new sensing method uses an integrated computation element (ICE) to combine the power and accuracy of high-resolution, laboratory-quality spectrometers with the ruggedness and simplicity of photometers. Many modern sensors typically merge the sensor with the electronics on an integrated computing chip to perform complex computations, resulting in an elegant yet simplistic design. Now, optical sensing using ICE features an analogue optical computation device to provide a direct, simple, and powerful mathematical computation on the optical information, completely within the optical domain. Because the entire optical range of interest is used without dispersing the light spectrum, the measurements are obtained instantly and rival laboratory-quality results.
A proof of concept MOC with ICE has been demonstrated, logging more than 7,000 hours, in nearly continuous use for 14 months. Oils with gravities ranging from 14 to 65°API have been measured in downhole environments that range from 3,000 to 20,000 psi, and from 150 to 350°F. Hydrocarbon composition measurements, including saturates, aromatics, resins, asphaltenes, methane, and ethane, have been demonstrated using the MOC configuration. As compositional calculations therein, GOR and density are validated to within 14 scf/bbl and 1%, respectively. The paper discusses the details of the new ICE-based sensor and describes its adaptations to downhole applications.
This paper will describe the state of art in active acoustic detection ofoil and gas in the water volume as well as the seafloor. Examples of real datawill be described with the relevance to the leakage detection challenges wheresurveillance and early detection is crucial. Active acoustic data will bepresented from several trials from various parts of the world, examples hereofis California natural seeps, Brazil leakage detection, Norway plume mixingphenomenon's and more.
Applications: Leakage detection on subsea assets, Site surveys of leakages,Oil response capabilities, Oil recovery capabilities, Dispersant efficiencyespecially sub surface, Quantification of leak flux both gas and fluid.
Results, Observations, and Conclusions: Expedition results will be reviewedbased on several real life tests and deployments of active acoustic systems.Conclusion of expected performance of active acoustic systems will be drawn.Miniaturization and adaptation of power requirement as well as uplink demand,combined with sufficient processing to avoid false alarms will bediscussed.
Significance of Subject Matter: Early subsea leakage detection is absolutelykey to any arctic project, quantifiable flux rates is an important key input toall decision-making during operation of oil fields in all regions.
Hole enlargement is a serious problem while drilling in permafrostconditions. The hole enlargement problems leads to lost circulation. Irregularand unstable holes also affect the quality of cement jobs. The drilling fluidis generally at a higher temperature than the permafrost formation. This causesa heat transfer from the drilling fluid to the formation. The ice particlesbinding the sediments together start to melt. This loosens up thesediments and causes caving. This paper proposes to minimize this problem witha low thermal conductivity fluid.
The drilling fluid can be cooled at the surface after it comes out of theannulus and before it is circulated back into the drill string. Cooling reducesthe temperature gradient between the fluid and formation. But this cooling isnot enough since the permafrost is at subzero temperatures and cooling to suchlow temperatures is not economically and practically feasible. This is wherethe innovative drilling fluid comes in. The drilling fluid shall have hollowmicrospheres. These microspheres are easily available commercially undervarious trade names. These microspheres lower the heat transfer coefficient ofthe fluid. This means that a significantly small amount of heat will betransferred from the drilling fluid to the formation. Low temperaturegradient and low thermal conductivity will work in conjunction.
The drilling fluid shall have a low heat transfer coefficient of 2.9-3BTU/hr.ft2.oF. The composition of the fluid and the heattransfer coefficient measuring experimental setup shall be discussed in thepaper. The paper shall also discuss the effects of heat transfer coefficient,circulation rates etc. on the thawing of permafrost.
The technique in this paper could go a long way in mitigating drillingproblems in permafrost regions.