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Al Shoaibi, S. (Petroleum Development) | Kechichian, J. (Petroleum Development) | Mjeni, R. (Petroleum Development) | Al Rajhi, S. (Petroleum Development) | Bakker, G. G. (Petroleum Development) | Hemink, G. (Shell Global Solutions International B.V) | Freeman, F. (Shell Global Solutions International B.V)
Fiber Optics Distributed sensing technologies are evolving in the petroleum industry with its potential applicability in many areas of surveillance. Petroleum Development Oman (PDO) is embarking upon the implementation of this technology in various assets including both Gas and Oil fields. The vision of the company is to have the Fiber Optics distributed sensing technology as a surveillance tool in the Well and Reservoir Management (WRFM) toolbox and to become, where appropriate, a key element of its cycle. In comparison to conventional surveillance, fiber optic distributed sensing requires no well intervention and thereby reducing HSSE exposure and production deferment. In addition, the installed fibers can be used for multiple applications, e.g. hydraulic fracture performance monitoring and inflow performance monitoring. Recently, PDO trialed Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) technologies utilizing both, dip-in surveys and permanent installation of fiber optics in the wells.
Fiber optic implementation in PDO included a polymer flooding trial in heavy oil, high permeability clastic reservoir with a strong bottom water aquifer drive. The objective was to monitor well conformance as the polymer injection progressed. The horizontal injectors were completed with pre-drilled liner and divided into four zones, each with an independent Inflow Control Valve (ICV). The well was completed with a multi-mode (MM) fiber pumped into control lines three injectors. Real time DTS data was acquired continuously in all three wells while DAS was acquired as per the injection program in one injector. DAS and DTS data were analyzed to quantify the changes in injection profile and rate in each ICV zone. This provided timely information needed for decisions related to manipulation of the ICV valves to ensure best utilization of the polymer.
Another example of fiber optics was a dip-in survey in a deep gas well with commingled production which covered stacked reservoirs. This was run in order to prove the concept of flow response on DAS/DTS signals in terms of gas flowing and liquid lifting detection. The acoustic signature observed was mainly due to gas entering the well through perforations. This was detected by DAS and DTS and allowed a qualitative inflow profile to be generated. The dip in survey proved the concept and allowed justification for the permanent installation of fiber optics behind casing. The objective of the permanent setup is to improve the sensitivity of the measurement and allow for better quantification of inflow per zone. In this paper, the approach of implementing fiber optic technologies in PDO is discussed with emphasis on value generation in the various assets. Additionally, the examples mentioned in this abstract are discussed in more details and based on the results, the way forward is described.
Buhassan, Shaker (Saudi Aramco) | Halder, Surajit (Saudi Aramco) | Tammar, Hassan (Saudi Aramco) | Beheiri, Faisal (Saudi Aramco) | Ahmed, Danish (Schlumberger) | Brown, George (Schlumberger) | MacGuidwin, Jeffrey Thomas (Schlumberger) | Haus, Jacques (Schlumberger) | Moscato, Tullio (Schlumberger) | Molero, Nestor (Schlumberger) | Manzanera, Fernando Baez (Schlumberger)
During the last 5 years, one of the most common matrix acidizing enhancement techniques used to improve zonal coverage in open hole or cased hole wells is conducting a distributed temperature survey (DTS) using coiled tubing (CT) equipped with fiberoptic and real-time downhole sensors during the preflush stage before the main stimulation treatment. This is used to identify high and low intake zones so the pumping schedule can be modified to selectively place diverters and acidizing fluids with a high degree of control. Once stimulation treatment has been completed, a final DTS analysis is performed to evaluate the zonal coverage and effectiveness of the diversion. Even though this technique has provided satisfactory results, alternative methods providing faster and more accurate understanding of flow distribution between the zones and laterals are needed, especially if there is limited temperature contrast between fluids and reservoir. Thus, an innovative coiled tubing real-time flow tool has been recently developed to monitor flow direction and fluid velocity. This measurement is based on direct measurement of the heat transfer from the sensors to the surrounding fluid using a calorimetric anemometry principle. The first worldwide use of this technology in a Saudi Aramco injector well showed this to be a viable new approach to downhole flow monitoring that can be used by itself or in conjunction with DTS, depending on the constraints of each individual intervention.
Harbi, Mesaad (Saudi Aramco) | Said, Rifat (Saudi Aramco) | Al-arnaout, Ibrahim H. (Saudi Aramco) | Haldar, Surajit (Saudi Aramco) | Al-Subaie, Fehead (Saudi Aramco) | Jenkins, Christopher Neil (Saudi Aramco) | Burov, Anton (Schlumberger) | Kharrat, Wassim (Schlumberger Middle East SA) | Ahmed, Danish (Heriot Watt University)
Water production is a serious challenge when stimulating wells in mature reservoirs. Production results after acidizing sometimes reveal a higher water cut; in some cases this change is significant enough that the well is no longer able to flow unassisted. A typical acid stimulation in the field follows a predetermined pumping schedule, where diverter is squeezed into the high water cut interval prior to injecting acid into oil zones. The diverter volume is based on a rule of thumb and the acid is pumped after assuming that the diverter is efficiently sealing the high water cut zone. Several coiled tubing (CT) matrix stimulation jobs have yielded production results of 100% water cut.
Prior to stimulation (a period of months or years), diagnostic logs were conducted to identify water producing intervals. Although, in some cases, the post-stimulation water cut may be as high as or higher than the water cut prior to the stimulation, suggesting that the diverter volume was not enough to seal the water zone. An innovative method is needed to confirm the isolation of high water cut zones before pumping acid, which would lead to increased oil production and reduce the risk of unintentionally stimulating water producing zones.
This paper shares a case history of a cased and perforated vertical oil well from a field in which the operator was able to reduce the risk of acidizing a high water cut interval through the innovative use of a fiber optic enabled coiled tubing (FOECT) string and a pressure-temperature casing collar locator real-time downhole measurement tool.
The distributed temperature surveys (DTSs) recorded with the fiber optic cable were used as an innovative method to identify the water producing zone. This method correlated with the water producing interval identified by a wireline log run some period prior to the CT job.
DTS allows the assessment of diverter efficiency and the tracking of fluids placement. In this case study, acid was confirmed to have been squeezed only in the upper oil zone. As a result, the well production increased significantly without any increase in the water cut.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127772, "Combining Distributed-Temperature Sensing With Inflow-Control Devices Provides Improved Injection Profile With Real-Time Measurement in Power-Water Injector Wells," by Drew Hembling, and Garo Berberian, SPE, Saudi Aramco, and Mark Watson, Sam Simonian, and Garth Naldrett, SPE, Tendeka, prepared for the 2010 SPE Intelligent Energy Conference, Utrecht, The Netherlands, 23-25 March.
Passive inflow-control devices (ICDs) are used to enhance the performance of horizontal producing wells in unfavorable environments such as nonuniform permeability and/or pressure variations along horizontal sections. ICDs were combined with a fiber-optic distributed-temperature-sensing (DTS) system to manage the water-injection profile across a reservoir horizon. This field trial demonstrated the effectiveness of the ICD system when used for injection-well profiling and for fluid diversion during acid stimulation.
To understand the injection profile and well performance, a DTS system was deployed with ICDs and swellable packers as a field trial in a planned injection well. The objectives were to provide real-time information on multirate testing, determine real-time compartmental-injection profiling, and eliminate the need for horizontal flowmeter logging and well intervention.
Recent designs use ICD-completion technology with a DTS umbilical deployed in the openhole producing section below a liner for real-time monitoring and controlling of inflow from each compartment, thereby extending well life and increasing recovery. This case involved the use of DTS and ICD technology to control injection profiles in an openhole near-horizontal well. Compartments were created by use of water-swellable packers with feedthrough capabilities for the DTS umbilical.
The reservoir section was separated into six compartments. On the basis of openhole-log analysis, the reservoir has a uniform porosity along the length of the well, with a few dolomite intervals present. The spacing of the ICDs and packers was planned in such a way as to isolate these dolomite sections while distributing the desired injection rate along the well. To mitigate the risk of getting stuck while running the lower completion to total depth, it was decided to limit the number of openhole packers to six, thereby reducing the number of allowable compartments.
DTS System and Installation
The DTS and a permanent downhole-monitoring system were installed in April 2009. The fiber-optic DTS cable was attached and secured to the production-tubing string and provides multipoint temperature profiles across the length of the well. The real-time data from the DTS system can be used for injection optimization and reservoir management by monitoring injection rates between and within the ICD compartments and by identifying crossflow conditions.
Passive ICDs (Inflow Control Devices) have been used in the past to enhance performance of producing horizontal wells in unfavorable environments such as non-uniform permeability and/or pressure variations along horizontal sections. This is the first ever attempt, to the best of our knowledge, at using ICDs combined with a fiber-optic DTS (Distributed Temperature Sensor) to manage the water injection profile across a horizontal reservoir horizon.
The cost of the permanent monitoring installation is comparable to a single coiled tubing deployed PLT intervention. This paper addresses how a passive ICD completion, utilizing DTS technology, was used to optimize and monitor well performance. In addition, the operational aspects of permanent vs. intervention monitoring are addressed while highlighting the opportunity for additional value creation using real-time monitoring combined with ICD technology.
This field trial demonstrates the effectiveness of the ICD system when used in an injection well for injection profiling and fluid diversion during acid stimulation. In addition, the DTS proved to be an effective alternative to production logging in this horizontal water injection well.
The key factor in the success of this project was the use of the 3-1/2?? ICD completion along with a DTS system to monitor and passively control the injection sweep across the entire reservoir section. DTS data were also obtained during pre-injection and acid stimulation operations. This was the first occasion in which an operator was able to evaluate stimulation efficiency of an ICD completion using permanent real-time monitoring methods.
To understand the injection profile and well performance, a DTS system was deployed with ICDs and Swellable Packers as a field trial for the planned injection well. Although previous systems have been run above the production packer, in cased multilateral wells, and in open hole ICD production wells1, 2, this was the first attempt worldwide to deploy a DTS system in an injection well with open hole completion across a passive ICD system. The objective of the field trial was to provide real-time information on multi-rate testing, indicate real time compartmental injection profiling, and eliminate the need for horizontal flow meter logging and well intervention.
The field trial considered in this paper utilized a nozzle type ICD design. The ICD acts as a restriction between the wellbore and annulus. The pressure drop across the ICD increases as a square of the flow rate, effectively preventing any one zone/ICD from providing a dominant outflow along the wellbore (See ICD equations on pg.13).