A company is selling a new well testing tool designed to be a cheaper, simpler way to do fiber optic sensing, and then it fades away. With the availability of more-complex smart-well instrumentation, immediate evaluation of the well response is possible as changes in the reservoir or well occur. Mechanical-diversion techniques can ensure acid injection into the various intervals of naturally fractured reservoirs. This paper presents results from full-scale testing of a flexible riser equipped with embedded sensors for distributed-temperature sensing (DTS).
This one-day course is an introduction to the emerging fibre optic technologies of Distributed Temperature Sensing (DTS) as well as related Distributed Acoustic (DAS) and Distributed Chemical Sensing (DCS). This programme looks at how these technologies work, and their application to the oil and gas industry. Such systems have been utilised in shallow steam injection wells as well as high-cost horizontal and multilateral wells where re-entry with a logging tool is difficult, if not impossible. This class also includes an overview of PLATO software for managing DTS data and computing flow, plus a hands-on demonstration of DTS hardware.
Distributed temperature sensing (DTS) data interpretation has been extensively used in the last 10 years for improving acid placement for matrix acidizing operations. The DTS data are used for injection profiling during or after the acid and diverter are pumped into the reservoir. This study proposes an improved treatment schedule option for optimizing matrix stimulation operations with coiled tubing. In addition to the well-established DTS flow-profiling model, the capabilities of the new model include wormhole modeling, acid placement, and skin calculations.
Coiled tubing-enabled optical fiber systems are usually used for improving the acid placement during or after matrix acidizing operations. A new model is proposed for designing and optimizing the matrix acidizing treatments in carbonate formations before, during, or after those operations. Specifically, this matrix acidizing model can be used in the pre-planning stimulation stage, before the DTS data is acquired, or during the stimulation, together with or separately from the DTS data. The model can be used in horizontal, deviated, and vertical wells with open-hole or perforated completions. The model takes into account the reservoir data (i.e., permeability, porosity, skin, pressure, and temperature), well data (i.e., tubing and casing sizes, length, number of perforations, etc.), and pumping schedule. Based on the input data and the wellbore hydraulic model, the output consists of the distributed acid rate and volume, wormhole length, and skin factor reduction.
The DTS data from a synthetic matrix acidizing operation similar to one performed in an offshore carbonate field is used to validate the new model. An analysis of the results obtained for the previous and improved models is included, identifying the factors affecting the validation. Understanding these factors is crucial, because the new matrix acidizing model has the potential for use in the pre-planning stage with an enhanced acid placement schedule and can reduce operational costs by not using an optical fiber during the stimulation. In addition, the matrix acidizing model can be used during the matrix acidizing operations and can significantly reduce the acquisition time for the DTS data.
In 2013, Devon Canada installed DTS in the trial production well at its Jackfish 2 asset. DTS was installed parallel to existing standard instrumentation. In early 2015, a distributed-acoustic-sensing (DAS) fiber-optic line was added in parallel along with multimode optic fiber, allowing simultaneous logging of DTS and DAS. DAS helped to improve confidence in and extend the definition of wellbore effects observed with DTS. DTS with a fiber-optic cable has been established as a reliable and tested method for monitoring thermal wellbores in heavy-oil production.
Society of Petroleum Engineers, 84379-MS, SPE Conference Paper, 2003, 6 p. 5. Brown, G.A., Kennedy, B., Meling, T. Using Fibre-Optic Distributed Temperature Measurements to Provide Real-Time Reservoir Surveillance Data on Wytch 20 SPE-189034-RU Monitoring of Real-time Temperature Profiles Across Multi-zone Reservoirs during Production and Shut-in Periods Using Permanent Fiber-Optic Distributed Temperature Systems. The Essentials of Fiber-Optic Distributed Temperature Analysis.
The article discusses the possibility of diagnosing the multiphase flow regime in the multilayered reservoir by using DTS (distributed temperature sensing) data. The analysis of the theoretical and actual curves of temperature build up and drawdown, corresponding to the main modes of multiphase flow of formation fluids are given in this article. The possibility of diagnosis of the multiphase flow regime is found based on analysis and interpretation of the characteristics of temperature buildup and drawdown in different intervals of the reservoir at the start of the well or shut in, or by changing opening degree of the choke. The possibility of diagnosing water breakthrough (WBT) intervals, based on the analysis of the changes in temperature curves according to the DTS is shown. For a more detailed analysis and interpretation of temperature change curves in the wells more frequent DTS measurements are required. It is necessary to conduct a comparative analysis of the dynamics of the temperature and pressure redistribution in the productive zone of the well, with the results of geophysical logging, production logging, taking samples of reservoir fluids from different zones of productive layers in the multilayered reservoir, moisture metering, hydrometry and others.
DTS with a fiber-optic cable has been established as a reliable and tested method for monitoring thermal wellbores in heavy-oil production. For its part, DAS has been established as a valuable diagnostic tool in unconventional reservoirs as a completion, stimulation, and production-monitoring tool. DAS interrogators turn a fiber-optic line into an array of thousands of virtual microphones, picking up acoustic signatures across a broad range of frequencies. In SAGD production, DAS has generated significant interest throughout the industry as a potential new reservoir-monitoring tool. This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180726, “SAGD Production Observations With Fiber-Optic Distributed Acoustic and Temperature Sensing,” by Warren MacPhail and James Kirkpatrick, Devon, and Ben Banack, Bryan Rapati, and Alex Ali Asfouri, Halliburton, prepared for the 2016 SPE Canada Heavy Oil Technical Conference, Calgary, 7–9 June. The paper has not been peer reviewed. This article is reserved for SPE members and JPT subscribers.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180726, “SAGD Production Observations With Fiber-Optic Distributed Acoustic and Temperature Sensing,” by Warren MacPhail and James Kirkpatrick, Devon, and Ben Banack, Bryan Rapati, and Alex Ali Asfouri, Halliburton, prepared for the 2016 SPE Canada Heavy Oil Technical Conference, Calgary, 7–9 June. The paper has not been peer reviewed. This article is reserved for SPE members and JPT subscribers.
In order to monitor the downhole production and injection conditions, as well as make decisions for well-performance optimization, the dynamic temperature data acquired from permanent downhole gauges (PDGs) and distributed-temperature sensors (DTSs) are often interpreted widely. In this paper, first, the relationships among bottomhole-pressure (BHP), -temperature (BHT), and flow-rate data were analyzed briefly by use of wavelet transform and nonlinear regression. Next, a nonisothermal wellbore model with complex structure was derived theoretically step by step. Then, the wellbore model was coupled with an existing reservoir model through BHT. After that, several synthetic cases were simulated to verify the wellbore model. Finally, on the basis of the coupled wellbore/reservoir model, the transient temperature behavior during flowing and shut-down periods was drawn out for well-testing analysis and some typical thermodynamic parameters were estimated by use of a set of field data.
Abu Roash-D is characterized as a carbonate reservoir in Abu Gharadig field, Western Desert of Egypt. It has a good lateral continuity, contains natural fractures with poor connectivity in addition to formation tightness. To further increase the production from the field, a full development plan for Abu Roash-D carbonate reservoir was initiated with drilling of horizontal wells. The main objectives of drilling such horizontal wells was to develop the tight unconventional reservoirs and increase production by dramatically increasing the contact area with the producing interval, maximizing drainage volume around a well and link the natural fractures network thus, achieving an economically production targets.
The effective placement of sufficient acid volume along the open-hole section of such horizontal wells provides significant challenges in acid diversion due to the high permeability streaks that requires a very effective diversion technique for optimal acid distribution a long the open hole lateral for a successful acid stimulation treatment.
A fiber optic enabled coiled tubing attempts to tackle some of these limitations. This new approach deploys downhole sensors with fiber optic telemetry inside the coiled tubing string provides a real time temperature, pressure and correlated depth measurments. The fiber optic telemetry allows distributed temperature surveys recording for obtaining temperature profiles across the entire wellbore. Monitoring the distributed temperature sensing (DTS) profiles accompined with downhole pressure data interpretation enables real time diagnostic of downhole events between the stimulation stages providing an important aid to further optimize and improve the performance of stimulation treatments.
This paper presents case histories of the first time implementation of horizontal wells in Abu Roash-D tight carbonate reservoir in Egypt's western desert in which fiber optic enabled coiled tubing was utilized to optimize stimulation treatment. The real time monitoring of downhole distributed temperature sensing profiles allowed the identification of both high permeability zones as well as tight zones across the entire openhole lateral. This enabled the operator to take pro-active decision on where to spot diverter or acid, select the best diversion technique and allow for treatment optimization.