One of the limiting factors affecting the length of horizontals wells has been the effective management of reservoir sweep with regards to wellbore influx. The added benefit of greater reservoir contact is met with increased differential drawdown across the well length and greater tendency to cut across heterogeneous formation with varying permeability. For many years, inflow control devices (ICDs) which restrict flow by creating additional pressure have been used to mitigate this problem. They are, however, passive in nature and once installed cannot be adjusted. In the event of water or gas breaking through in an oil well the disadvantage of the passive ICD become evident as the well would be quickly overtaken by the breaking fluid since they are usually designed to choke oil. Autonomous ICDs (AICDs) are, however, self-regulating and are classed as active. Unlike its passive counterpart, which produces greater choking for higher density fluids, they in addition to choking oil, choke water and gas more readily. This prevents the well from being flooded when unwanted fluids break through therefore providing the advantage of being able to even out inflow into the well and in addition, choke compartments producing unwanted fluids leading to greater recovery, lower water cut and gas production. This paper provides a comprehensive model of the autonomous ICD and goes further to show how this can be applied to modelling its influence on inflow distribution in a completed well system. The model is validated by comparing results obtained with tests carried out in a flow loop. A comparison of results obtained from the autonomous ICD and passive one is also shown to highlight the effectiveness of the autonomous ICD in flow regulation over the passive ICD.

The uneven distribution of the production influx from the reservoir into the wellbore has been identified as the main issue in the management of production in heavy oil wells. This occurs due to a drastic difference between the mobility of oil and water i.e. water flows faster than oil in these reservoirs. This can be exacerbated by reservoir heterogeneities resulting in very high water production rate requiring large water treatment facilities which may be limited in offshore developments, resulting in reduced oil production. Advanced well completions utilizing Inflow Control Devices (ICDs) and Autonomous Inflow Control Devices (AICDs) have proven to be robust solutions for these problems. Both devices help to enhance the performance of heavy oil wells by delaying the water production, however, AICDs are more capable to reduce the water production and increase oil production even after water breakthrough. This paper examines the heavy oil/water production control by ICDs and AICDs and discusses the flow loop test data (single and multiphase flow) to describe the performance of devices for various fluids under downhole conditions. Using an example model, the reasons for the superiority of AICD over ICDs is investigated under different scenarios. An optimisation workflow was used to optimise the well completion design i.e. the size and number of devices plus packer placements and numbers. The results of several field applications of AICDs, from retrofitting the existing completions of the wells with very high water cuts (e.g. 98%) to brand new wells in heavy oil fields, will be discussed. AICD completion as a proactive-reactive device was found to be the most efficient completion at controlling the water production from high productive zones or the fractures, compared to the wells equipped with ICDs and other conventional completions while increasing oil production. This paper provides insights about inflow control device applications in heavy oil wells and provides a comprehensive guideline on the selection of appropriate completions for the wells in these challenging reservoirs.

This paper describes the application of down-hole monitoring technologies to a coal seam gas (CSG) field located in the Bowen Basin in Queensland, Australia. The monitoring technology includes both conventional bottom-hole pressure sensing and the newer, fibre optic-based Distributed Temperature Sensing (DTS). As one of the first applications of DTS in a low permeability CSG well we will review the method of installation, data gathered and application of this data for monitoring production from multiple intervals in a single coal seam. The coals in the Bowen Basin region are characteristically of low permeability, and multi-seam hydraulically fractured wells are commonly deployed as a result. All wells require artificial lift; as a result, water is produced up the tubing string, generally with the assistance of a Progressing Cavity Pump (PCP), whilst gas flows up the annulus. Whilst this is an economic method of evaluating the performance of multiple formations simultaneously, the key limitation of this practice for appraisal purposes is that only total, commingled production for each phase is measured at surface. Given the requirement for artificial lift, production logging techniques are currently unavailable to assist in this multi-seam production allocation, meaning that typically, a reservoir simulation history-matching process is required to estimate the relative performance of individual formations based upon regional trends derived from core measurements or static well logs, often with little justification to adjust parameters outside certain ranges. Any unexpected changes in these reservoir parameters (gas content, permeability, etc.) or completion properties (perforation / stimulation effectiveness) between layers can give rise to dramatic differences in production contribution, which may impact the assessment of which formations (or collection thereof) are prospective targets for further development. DTS allows the measurement of a continuous flow profile during desorption and subsequent production. This allows for better understanding of any such heterogeneity between production intervals, and an improved understanding of the reasons for production variation both at start-up and over time. This paper will present DTS data acquired over the initial stages of the well life and show how the thermal behaviour changes over time with production. We will discuss how the thermal profile is related to the well production rate, and describe some of the complexity involved in the inversion process when converting a thermal profile to a production profile. This inversion is especially complex as a typical CSG well is completed with artificial lift and has flow in both the tubing and annulus. This creates separate, but coupled, thermal responses in the tubing and annulus. The well performance and thermal behaviour also depends on the liquid level in the annulus, which is itself controlled by the rate of the PCP.

Поддержка продуктивности, путем ограничения прорывов газа и воды посредством технологии автономного контроля притока Бенн А. Волл, Исмаруллизам Мохаммед Исмаил, Ико Огуче, Тендека Авторское право 2014 г., Общество инженеров нефтегазовой промышленности Этот доклад был подготовлен для презентации на Российской технической нефтегазовой конференции и выставке SPE по разведке и добыче, 14 -16 октября, 2014, Москва, Россия.Данный доклад был выбран для проведения презентации Программным комитетом SPE по результатам экспертизы информации, содержащейся в представленном авторами реферате. Экспертиза содержания доклада Обществом инженеров нефтегазовой промышленности не выполнялась, и внесение исправлений и изменений является обязанностью авторов. Материал в том виде, в котором он представлен, не обязательно отражает точку зрения SPE, его должностных лиц или участников. Электронное копирование, распространение или хранение любой части данного доклада без предварительного письменного согласия SPE запрещается. Разрешение на воспроизведение в печатном виде распространяется только на реферат объемом не более 300 слов; при этом копировать иллюстрации не разрешается. Реферат должен содержать явно выраженную ссылку на авторское право SPE.

This paper discusses the use of permanent Distributed Temperature Sensing (DTS) using optical fibres for flow zone allocation in Coal Seam Gas (CSG) production wells. In a commingled well the allocation of total well production to the multiple stacked reservoir units is extremely important. Understanding which zones are most productive can influence future development decisions and operational practices. Additionally, the subsurface reservoir model can be calibrated and verified from the data, improving the accuracy of any forecast derived from the model. At QGC, well completion design has focused on simplicity to drive efficiency in the execution of the ca. 2,500 wells drilled so far. These open hole completions have been run with a pre-perforated liner and no external packers to separate formations. This adds uncertainty to the interpretation of results from conventional wireline production logging tools (PLTs) run inside the pre-perforated liner. To perform a conventional PLT, the down hole pump for dewatering must be pulled, requiring a rig and making flow allocation data acquired by PLT very costly. DTS is seen as a viable alternative to PLTs, with the measurement fibre run permanently on the outside of the casing or tubing. It can remain in the well during pump operation and gather data throughout the life of the well. Typically, at QGC, a recording is made every 6 hours and is transmitted to a cloud based database for immediate visualisation. Since a temporary single day DTS installation was trialled in 2014, QGC has run 11 permanent fibres across its Surat CSG development. This has yielded valuable information on production allocation and depletion trends. There have also been a number of challenges encountered. These include interpretation of dual phase flow, and identifying the correct geothermal gradient for interpretation. The advantages and disadvantages of casing conveyed versus tubing conveyed DTS installations are also discussed.