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From using history matching to recording microseismic; exploration, completion, and production groups in the oil and gas industry don't know exactly where stimulation treatments are placed and how efficient that placement has been. Exploration geologists and geophysicists want to know placement effectiveness to relate current geologic parameters with future potential formations. Completion engineers want to use tubular and downhole hardware systems to be as cost-effective as possible and to minimize total stimulation treatment cost. Production engineers are seeking to maximize production for as long a time frame as possible. Fracturing placement and verification cuts across all segments of an asset.
With recent technology and methodology advancements, the industry can inject particulate oilsoluble tracers (OST) with the proppant and measure those tracers effectively from fracture tip to production tank. While still not accurately describing the exact fracture geometry or parameters such as fracture conductivity (fcd), the industry can now qualitatively measure production from each stage. With each stage uniquely identified by post-fracture production, fracture size and capital expenditure associated with the placement of the fracturing treatment can be optimized.
Broadview Energy recently pumped a fracturing treatment into the 637 m (2089 ft) total vertical depth (TVD) Sparky clastic zone through a 114 mm (4.5") liner string in a horizontal wellbore using mechanically operated sleeves. Broadview Energy sequentially alternated the size of the fracturing treatments along the length of the well between 7.5 t (16, 534 lb) and 5 t (11,023 lb) of 16-30 fracturing sand as the proppant. Alternating the fracture size served to isolate geologic and fluid heterogeneities.
Measuring the OST concentration from each fracture treatment showed results that were not directly proportional with the size of the treatment; namely, a 50% larger stage treatment yielded a 33% improvement in OST return. Using tracer technology to show observable variations of completion methods, Broadview Energy hypothesizes that, with further testing, it would be possible to recognize the threshold in fracture size and prevent diminishing returns in future fracture treatments with similar geologic conditions.
The objective of this paper is to describe the first application of three unique chemical tracer technologies in the optimization process of a field development in the Black Sea offshore Romania. These technologies helped in the understanding of fluid flow, fracture effectiveness, and completion design. The paper describes the methodology employed and the results obtained from the combined application of water tracers, oil tracers, and gas tracers in one multistage hydraulically fractured well. Additionally, the tracer design, operational logistics, operational lessons learned, results interpretation, and application of the results in order to improve subsequent completions will also be discussed. Clear correlations were seen between the results of all three tracers, which were in turn compared to production and treatment data, further confirming the value of diagnostic technology. The importance of adequate sampling and offshore operational limitations were identified and resolved. Results from a planned, but due to tracer results, not executed water shutoff of high watercut zones are presented. The results were applied to future completion designs and decision-making processes. This case study is an inside look at the first-ever combined application of oil, water, and gas tracers in an offshore hydraulically fractured well development in Europe. It will discuss how the results from using all three chemical tracer technologies, coupled with additional data sets while applying a synergistic interaction between teams, can be highly leveraged to understand current completions designs and optimize future developments.
The applications of tracers can be tied to most disciplines in the oilfield; from drilling to secondary and tertiary recovery. The focus of this paper is in the application of chemical tracers to completion diagnostics and optimization, and in particular, to multistage fracturing operations offshore.
In the multistage fracturing application of tracer technology, there are mainly three sub-categories of chemical tracers: tracers for the gas phase of hydrocarbons, the liquid phases of hydrocarbons, and tracers for the water-based completion fluids. The presented project utilized all three tracer types at the same time.
Abstract Inflow distribution monitoring of long horizontal wells is a challenging issue. Input from such surveillance is needed to verify the clean-up of the well; to monitor the functionality of the completion solution; identify early water breakthrough; to calibrate the reservoir model, and to optimize the drainage strategy. These steps are crucial for increased oil recovery (IOR). A dual lateral well equipped with unique chemical inflow tracers distributed across ten compartments has been installed in a marginal field development on the Norwegian Continental Shelf. The Hyme oil field development utilizes a 20 km subsea tie back to a platform where the inflow tracers are sampled. The monitoring efforts assess well performance from the clean-up, cross flow and back pressure in each lateral. Traditional wire-line conveyed production logging was not an option in the field's monitoring strategy due to lack of wire-line access to the reservoir zones. The multi-year life length of the deployed chemical inflow tracers enables monitoring of the well for a substantial period of time. Tracer samples are acquired on a regular basis depending on monitoring objectives. In addition, a large number of samples were acquired after a shut-in period to catch the flow-induced transient responses of the different tracers. Parameters such as clean-up quality, cross-flow during shut-in and back-pressure in the two branches were interpreted from tracer appearance, including peak arrival timing and overall shape of the different tracer transient responses. The tracer transient monitoring technology enabled quantification of oil contribution from each compartment in each lateral. A history matching process was used to match the observed tracer signatures after a shut-in period using a transient inflow tracer model that has been experimentally verified by flow-loop experiments. The estimated inflow profiles show good agreement with expected result, based on the reservoir properties, and what was acquired from individual testing of the two branches. The initial information gained since first oil has been valuable in understanding early production performance and updating transient wellbore and reservoir models for assessing well performance in relation to increasing field recovery without the need for interventions.
Shan, Youngbin (EverGreen Energy Service, LLC.) | Huang, Wei (O&G Technology Research Inst. Of PetroChina CQ Oilfield Company) | Liu, Hanbin (O&G Technology Research Inst. Of PetroChina CQ Oilfield Company) | Gan, Qingming (O&G Technology Research Inst. Of PetroChina CQ Oilfield Company) | Lv, Yiming (O&G Technology Research Inst. Of PetroChina CQ Oilfield Company) | Zhao, Chun (O&G Technology Research Inst. Of PetroChina CQ Oilfield Company) | Zhu, Hongzeng (O&G Technology Research Inst. Of PetroChina CQ Oilfield Company) | Li, Zhijun (O&G Technology Research Inst. Of PetroChina CQ Oilfield Company) | W, Yaoguang (EverGreen Energy Service, LLC.) | Yang, Youwen (EverGreen Energy Service, LLC.)
Abstract Find & Plug is defined as locating water zone in either vertical or horizontal well and shut it off. The most challenging job in a horizontal completion well is to locate the water producing zone, especially after a period of production over time. Once the water producing zone is precisely located, either mechanical or chemical isolation can be deployed to shut the zone off. PLT and donwhole monitoring such as fiber optical and downhole gauge are common technologies to locate the water zone. PLT log is somewhat risky and/or questionable to determine zones production profile when well relies on sucker rod for production or horizontal completed. Data is only for 6-12 hours duration which may not reflect the dynamic change of reservoir water influx. Fiber Optics can only measure zone pressure and temperature. To achieve the production profile, a mathematical model must be setup. Many parameters in the model are estimated and therefore the calculation or simulation of water producing downhole is overall questionable. Permanent gauges have to be deployed attaching onto tubing or casing. Wire has to go down to production zones thru the tubing or casing. It will take some rig time and is costly to deploy. This paper proposed a new model using polymer tracer to deploy with tubing alongside the production zones, either vertical or horizontal, with or without packers for isolation of each zone, to measure the liquid profile of interest zones at initial production and water profile of interest zones over a period of production. By deploying the polymer tracers near the production zones, the tracer sub will be installed atop or below the zones depending on where the ICV is located. When liquid and water produced from each zone, it must pass through the tracer sub where the tracers will dissolve into the produced water at initial stage and diffuse into produced water after the dissolution process is almost saturated. Surface samples of liquid and water will be taken by a designed sampling program and sent to lab for analysis. Analysis data will be interpreted by SHANIP and SHANWC model. SHANIP model is a mathematical formula which establishes relationship between produced tracers and zone liquid concentration at initial production. SHANWC model is a mathematical formula which establishes relationship between produced tracers and zone water concentration after the dissolution process is almost terminated. If packers are installed between interest zones to isolate the zonal production, SHANIP and SHANWC model can quantitative measure each zone liquid production and water concentration over a period of production. The period can be 6 months, 1 year or even longer depending on the amount of tracers installed and volume of water producing. If no packers are isolated between interest zones, a qualitative analysis to zonal water cut can be achieved. Those include major water producing zones, no production zones, low water cut zones, etc. With SHANIP and SHANWC models, clients and researchers in O&G can easily and economically evaluate the zones water cut at any time they wish. And no intervention is necessary except for the first tubing deployment.
Abstract North Amethyst is the first subsea tieback field development for Husky Energy’s White Rose project, located off the East Coast of Newfoundland and Labrador, Canada. The geographical location presents some of the harshest weather conditions in the world due to the elevated sea states and ice conditions. The North Amethyst field achieved first oil in 2010 and at the end of December 2011, had three production wells and three water injectors. Further wells are planned as part of the development. To counter imbalance in the horizontal flow profile that can lead to early water or gas breakthrough, the field development strategy employed Inflow Control Device (ICD) technology. The ICD technology application was the first offshore on the East Coast of Canada. A method of proving effective horizontal clean-out and flow distribution for the ICD technology was necessary. However, due to the subsea configuration complexity, semi-submersible rig costs and delays due to unfavorable weather conditions, the prospect of production logging the horizontal wells was deemed a high risk and expensive operation. To overcome these hurdles, unique inflow tracer technology was used in tandem with the ICDs to provide validation of clean-out and horizontal flow distribution. The North Amethyst producers were equipped with unique oil and water soluble tracers placed along the horizontal, embedded in the ICD screens. The tracer technology’s objectives were to monitor the zonal contributions during clean-out and during the production phase. Water tracers were to monitor and identify the location of zonal water breakthrough. Topside fluid samples were analyzed, and tracer concentrations provided the basis for extracting well inflow information. The utilization of inflow tracer systems in collaboration with other reservoir engineering tools has provided validation of horizontal contribution and feedback about individual ICD nozzle placement. This paper will document the design, execution, and analysis of the tracer results in two initial North Amethyst ICD producers.