Understanding flow distribution across the well is significant piece of surveillance and important input for decisions related to well and reservoir management. Companies face significant challenges to monitor it. DTS is one of the technologies to mitigate challenges and minimize surveillance costs. As part of surveillance plan of ACG Res02 pilot program, DTS has been installed on a newly drilled gas injector (GI1). Significant learnings have been acquired from this trial.
GI1 was drilled as part of a pilot program on Res02 reservoir, which is currently at early stages of development. It has been equipped with number of surveillance tools as well as DTS across the whole sand interval. DTS profile on injector was generated based on difference in temperature of injected fluid and reservoir. Specifically in ACG environment injected gas temperature is higher than that of reservoir. Hence, warming effect was expected on the zones taking injected gas where due to heterogeneous nature of the reservoir, uneven injection into sublayers can occur.
DTS enabled real-time monitoring of how temperature profiles change across the sands and revealed uneven distribution of injected gas across the reservoir. When gas injection rate was increased, clear change in temperature profiles was observed – injection was getting into the lower sands as well. Moreover, shut-in DTS traces helped more accurately identify gas taking sands based on coolback effect. As injected gas temperature is higher than the reservoir temperature, temperature profile will be cooling back towards the geothermal gradient once the well is shut-in. This can be considered as warmback analogue that can be seen in water injector temperature logs.
Introducing DTS on gas injectors is both cost efficient and provides continuous flow monitoring, which enables real time decision making. Since it is dealing with only one fluid phase (gas) it provides more certainty. Information gathered from DTS will have a strong impact on field development planning, pressure maintenance, as well as smart completion designs.
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.
The industry’s continued migration into deeper, hotter, and more unconventional oil and gas reservoirs carries the potential for significant financial rewards and major economic risks. Because the development of unconventional reservoirs often requires some form of stimulation—thermal stimulation for heavy oil formations and hydraulic fracturing for shale plays—well construction costs are reaching new highs. Rather than developing these wells in a trial-and-error or even blind fashion, more operators realize that the only way to maximize the value of these assets is through real-time monitoring at the reservoir level.
Permanent reservoir monitoring calls for the deployment of one or more downhole sensors to monitor and record a number of reservoir properties, such as temperature, pressure, and flow rates at various locations in and around the wellbore. By monitoring these properties in real time and over time, operators can gauge the progress of reservoir development at each stage of the well’s life cycle.
Full-Asset Life Cycle Benefits
During fracture stimulation of shale wells, for example, a permanent monitoring solution can reliably report information on the fracture network being created, including data on both the quantity and quality of fractures being created in different zones. In steam-assisted gravity drainage (SAGD) wells, downhole temperature sensors can track the propagation of steam moving into the formation, and then the progress of heated oil moving into the producing well.
Once the well is brought onto production, these same monitoring tools can accurately measure the pressures, temperatures, and flow rates of fluids at different points in the wellbore and from different producing zones. Such insight informs when the operator may need to implement some form of remediation or artificial lift in the well to boost dwindling production rates. Once artificial lift has begun, the real-time reservoir data can help optimize the pumping rates of various lift technologies to maintain production at desired rates.
The benefits of permanent reservoir monitoring extend past a single well to encompass production optimization at a field level. For example, by installing permanent sensors in producing, injection, and monitor wells as part of an enhanced oil recovery (EOR) campaign, the operator can feed these data into simulation models to track production across the reservoir. Such information can then be used to aid development decisions—an expansion of EOR or the drilling of additional wells—to boost the long-term production of an entire field.
Weighing Monitoring Options
The past 2 decades have brought an impressive pace of development for different permanent downhole monitoring options. For operators, the choice of a system is a function of several interrelated factors.
Al-Gamber, S. D (Schlumberger) | Mehmood, Sajid (Schlumberger) | Aramco, Saudi (Schlumberger) | Ahmed, Danish (Schlumberger) | Burov, Anton (Schlumberger) | Brown, George (Schlumberger) | Barkat, Souhaibe (Schlumberger) | Shrake, Gwynne (Schlumberger)
Proven to maximize hydrocarbon production or well injectivity, horizontal multilateral completions have witnessed growth both in number and complexity over the years. These well types brought challenges with respect to well accessibility for rigless well intervention, and the ability to access these wells has been developed using coiled tubing (CT) to enable operations, such as reservoir stimulation, to be carried out.
One of the main challenges is to identify and access each lateral, to be able to perform the stimulation to maximize well production. This challenge has been encountered in Saudi Arabian multilateral wells, which are drilled in a carbonate reservoir with an open hole (OH) completion and where the laterals are typically left with a high formation damage (skin effect) after drilling, thus requiring stimulation to improve their performance.
At present there is no single technique for lateral identification without tagging TD. In this paper we describe how a combination of multilateral tool (MLT) along with CT downhole measurement system is used to locate and access laterals, selectively acquiring a gamma ray profile across each of the laterals, then optimizing the stimulation operation using distributed temperature survey (DTS) measurements.
This paper discusses the planning, execution and evaluation of the results in a stimulation job performed on an open hole multilateral water injector employing a CT with fiber optics that enables a real-time downhole measurement tool (pressure, temperature, casing collar locator, gamma ray) and MLT. The results highlight the effectiveness of the technique in maximizing the wells performance.
Issran field is located 200 km east of Cairo-Egypt, producing from fractured dolomite reservoir 8-12 API oil gravity. The reservoir depth ranges from 1000-2000 ft, with BHP 300-500 psi and BHT of 120-200 F. The heavy oil viscosity is 4000 cp at standard conditions and the reservoir rock is oil wet with high H2S content. The high viscosity and low mobility of the Issran field heavy oil in contrast with the strong mobility and low viscosity of the formation water had extended the problem to a severe decline in hydro carbon production.
In an attempt to enhance the production, Steam injection had been deployed in the field to reduce the oil viscosity and hence enhance the mobility of the extra heavy oil. Enhancement in production has dramatically increased after implementing a new technique combining the Steam Injection with the Matrix Stimulation Engineering Utilizing the Fiber Optics Telemetry Enabled Coiled Tubing.
As the first time in the East Africa and East Mediterranean countries, the new technology deployed (Fiber Optics Telemetry Enabled Coiled Tubing) has provided a new dimension to the heavy oil thermal recovery by supplying a full Distributed Temperature Survey (DTS). Real time interpretation of the DTS data enabled the real time decision making during the Matrix stimulation treatment based on the actual downhole parameters. It also provided valuable data regarding mapping of the downhole steam injection utilizing coiled Tubing.
This paper assesses the effect of using the new technology in Coiled Tubing services utilizing the DTS Measurements during Matrix Stimulation Treatment in different wells. It analyses the Successful production enhancement that provided a new dimension to the extra heavy oil enhanced recovery efficiency. It also quantifies the economical added value resulting from the usage of DTS data in respect to conventional matrix stimulation with conventional Coiled Tubing.
Brunei Shell Petroleum (BSP) first started completing Smart Wells in 1999, trialing standalone technologies such as permanent downhole gauges and inflow control valves in individual wells. Once these were seen as successful, the technology was used extensively on a single platform. This was later extended to application in a whole field, taking advantage of refinements such as variable downhole control valves and multiphase flow metering.
Learning from the successes of other oil producing fields such as Champion West and Bugan, Seria North Flank was planned and designed as a fully Smart field. Seria North Flank would be the first field to fully integrate Smart technology with Smart field processes, improving the efficiency of Well and Reservoir Management activities and accelerating reservoir understanding in order to reduce uncertainties for future development. This resulted in the development of over 120 million barrels of oil, with improved Unit Technical Costs compared to an offshore development.
Building Smart capabilities
Brunei Shell Petroleum (BSP) initially trialed the individual elements of Smart technology in standalone wells from 1999. Downhole gauges and fibre optics (for Distributed Temperature Sensing, or DTS) were run on different wells, mainly to trial the technology and study reservoir inflow profiles. Several key findings from these wells formed the basis for the requirements of surface operated inflow control valves (ICV). The main one of these was that contribution from long horizontals tended to be negligible from the toe of the well (furthest from the stinger section).
The Champion West field was selected to further develop Smart technology. In order to manage and develop appropriate solutions for the network infrastructure, a dedicated IT team was created to support to real time data management. A small team within the operations discipline was also formed to help manage the interfaces with the existing offshore network infrastructure.
Initial completion designs incorporated one ICV above a ball valve and a dual gauge for multizone wells. At this stage, only monitoring was applied remotely with the downhole and surface gauge data transmitted to the main production facility and control requiring human intervention at the platform location. These wells showed the time benefits of have surface operated capabilities to monitor well pressures and change zones. In 2002, Shell started to develop the Smart Fields program, defining the technology and processes required in order to operate a Smart Field.
In 2003, the surface control was further developed so that remote operations from one of the Champion West jackets was possible from the main production platform and then from the Head Office. These successes led to the development of the Champion West Drilling Platform in 2005, a fully Smart, not normally manned platform. This platform incorporated almost all aspects of Smart technology that were available commercially at the time, with almost all aspects of the wells operated and monitored remotely. Surface flow control valves and sequencing valves to control surface rates and select wells for testing, a multiphase flow meter to accurately test wells, and the full suite of downhole tools that included inflow control valves to control flow, permanent downhole gauges for pressure data and fibre-optics to acquire distributed temperature surveys. Each well had up to five individual zones to maximize hydrocarbon recovery and value.
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.
Monitoring the temperature profile of a well over its entire producing zone or entire length allows state-of-the-art analytical methods to be used. Heavy-oil producing fields generally employ some form of thermal-enhanced oil-recovery technique. In many cases, a field consists of producing, injection, and observation wells.