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Driven by ever increasing associated costs, the industry has long sought an enabling technology to expedite hydraulic fracture cycle times in high cost environments such as offshore. Remotely operated completion tools have been proven to provide these efficiencies and can positively influence the viability of these multi-zone stimulation projects.
This paper will focus on the planning and execution of an offshore North Sea lower completion to present a methodology to remotely access and isolate the reservoir during multi-zone stimulation operations. Innovative technologies utilized in this case study are presented which effectively minimize the cycle time of the stimulation process while providing a high level of contingencies to account for a panoply of scenarios which could occur through-out the operation.
There are several techniques and methodologies which have been deployed to efficiently stimulate multi-zone, horizontal wells in offshore locations such as those found in the North Sea; technical papers such as (
The selected remotely operated lower completion system incorporates multiple communication methods on-board to permit remote functioning of flapper isolation valves, to compartmentalize the reservoir internally, and remote operated stimulation sleeves to access the reservoir, which effectively eliminates the need for intervention between treatments, ultimately improving fracture cycle time and reducing risk while providing operators with realistic contingencies in the event of screen-out.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27183, “Current State of the One-Trip Multizone Sand-Control-Completion System and the Conundrum Faced in the Gulf of Mexico Lower Tertiary,” by Bruce Techentien, Tommy Grigsby, and Thomas Frosell, Halliburton, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.
This paper provides perspective on the current state of multizone completion technology and issues encountered in the industry with developing a system that offers increased capabilities to meet the increasing challenges presented by the Lower Tertiary in the Gulf of Mexico (GOM). The multizone technology has proved to be an enabler for cost-efficient completions in the shallow-well environment and in the high-cost ultradeepwater environment requiring high-rate fracture-stimulation treatments.
Lower Tertiary GOM
The Lower Tertiary play is south and west of the Miocene area in the GOM and is, consequently, in deeper water. The Lower Tertiary is located approximately 175 miles offshore and is estimated at 80 miles wide and up to 300 miles long. Water depths are from 5,000 to 10,000 ft. Production targets are at depths of 10,000 to 30,000 ft subsea.
The Tertiary trend is from 66 million to 38 million years old. Within the Lower Tertiary, the Lower Wilcox portion presents sheet to amalgamated-sheet sands considered to be part of a regional basin floor fan system.
The Late Paleocene to Early Eocene (Wilcox equivalent) reservoirs are considered to be laterally extensive sheet sands that were deposited in deep water. These reservoirs are distributed across an area largely covered by the allochthonous Sigsbee salt canopy. It is this canopy that causes additional problems beyond merely the water depth and the well depth required to reach the reservoirs.
These exploration plays depend on understanding the updip fluvial/deltaic stratigraphic architecture and the potential for partitioning of reservoir-quality sandstones across the depositional shelf into the slope and basin floor environments. The Lower Tertiary is estimated to contain up to 15 billion bbl of oil.
Current State of Multizone TechnologyThe Generation IV multizone system has been deployed successfully in the Lower Tertiary by multiple operators. To the authors’ knowledge, the multistage completion system and enhanced single-trip multizone fracturing systems had been installed in 10 wells as of the summer of 2015, with additional well installations planned. These systems are rated to 10,000 psi, and the enhanced single-trip multizone tool system offering an open-hole variant was installed in one five-zone completion.
Østvik, Egil (Norsk Hydro) | Hansen, Helge Bjorna (Norsk Hydro) | Rasmussen, Lars (Norsk Hydro) | Malmanger, Eva Mette (Norsk Hydro) | Tønnessen, Sven Harald (Rogalandsforskning/Triangle Technology) | Browne, Paul L. (Halliburton Energy Services, Inc.) | Williamson, Jim (Halliburton Energy Services, Inc.)
Norsk Hydro operates the Snorre Field in the Norwegian sector of the North Sea with a tension leg platform (TLP) and a sub-sea production system. The initial sub-sea wells were designed with completions that would allow through-flow-line servicing, and while the wells were functioning as designed, production had been declining. Therefore, Norsk Hydro felt that the completion concepts should be evaluated for new field developments. The ensuing investigation and development project led to a novel well completion concept, which is the first "intelligent well" subsea completion installation offshore Norway.
This innovative design changes retain the original through-flow-line (TFL) service technique system and subsea infrastructure without any modifications, maximize production by introducing 7-in. tubing, and include hydraulically operated inflow control devices.
The supplier and operator developed the concept during the winter 1998/1999 and designed the resulting system during spring 1999.
License approval for prototype development and qualification was given in the summer of 1999, and the system components were in-house tested at the supplier base in Dallas during the fall of 1999. A thorough system qualification was performed at an independent Norwegian drilling and well test center during spring/summer of 2000. The qualification included a full test-well installation and necessary intervention activities to prove the functionality of the concept. The system was qualified during the summer of 2000. The first subsea well installation was done at Snorre and put on production in December 2000. The well completion consisted of a 4-zone/interval design for improved reservoir management.
The concept principles also have application for other type wells on platforms where modifications to the wellhead and tree are not feasible.
The development process and qualification of the system has been conducted in a very short time period from idea to offshore implementation. This is mainly the result of a very focused personnel team with competent and dedicated personnel between supplier, operator, and 3rd party testing contractor.
This paper will discuss the improved system and testing that resulted from this project. The first new production system was installed in a side-tracked well, and the results of the completion will also be discussed.
The Snorre Field is located in the Tampen area in the Norwegian sector of the North Sea (Fig. 1). The field was discovered in 1979, and production commenced in 1992. There are two main reservoirs - the Triassic Lunde Formation and the Triassic-Jurassic Statfjord Formation with approximately 70% of the estimated oil in the Lunde Formation. Production commenced in 1992.1 The field was developed with a tension leg platform (TLP) in the southern part of the field and a sub-sea production system (SPS) in the eastern part. The SPS has capacity for ten wells, ten inboard slots, and ten additional outboard slots for later wells. The SPS and well completions are unique as TFL techniques are used to service the wells.2 This method allows downhole service tools (i.e., insert safety valves,3 logging tools, plugs etc) to be installed remotely from the TLP by pumping the tools through the flow lines and into each of the wells. These wells were originally completed using dual 3-1/2 in. tubing, a Y-block, a single 9-5/8-×3 1/2-in. production packer, and a single tail pipe in the 7-in. liner. Because of declining production, the operator felt that improvements were needed in the completion design for future wells. Thus, the following events were initiated.
Aripin, Izura (PETRONAS Carigali Sdn Bhd) | Faisalluddin, Teuku (PETRONAS Carigali Sdn Bhd) | Allapitchai, M Shahril Majid (PETRONAS Carigali Sdn Bhd) | Hamidy, Hudzaifah Zol (Halliburton Energy Services) | Ghazali, Ikmal Hakim (Halliburton Energy Services) | Ab Latif, Ahmad Syauki (Halliburton Energy Services) | Govinathan, Kesavan (Halliburton Energy Services) | Priatna, Oktaf (Halliburton Energy Services)
Abstract This paper presents a case history in which a single-trip multizone sand control system was successfully deployed in Malaysia using a hydraulic workover (HWO) unit. The well consists of two (2) zones which were both treated and completed in a single-trip gravel pack system. This paper discusses in detail the design selection and operation, which includes the challenges faced and mitigation to overcome the challenges. All operations involved were completed with a significant time and operational cost saving to the operator. This was the first successful single-trip multizone installation using HWO globally. The sustained prolific oil production from this well affirms the success of the completion and gravel pack treatment method. These positive results highlight the importance of operator technical/operations personnel and service providers working as a team to develop the most appropriate solutions to the technical and operational challenges encountered.
Although multiple-zone, downhole sand-control-tool systems have been in use since the early 1990s, these systems have been designed for jobs that require only low pump rates with low pressure differentials. Multiple-zone systems capable of high fracturing pump rates and the associated differentials only recently have been introduced to the oil field, but most of these completions have been limited to four or five treated zones. This paper presents a case history from Indonesia in which six discrete zones in an offshore deployment were treated successfully in a single trip. The Bawal field is located in Block B, 1000 km north of Jakarta, in the South China Sea. The average water depth across the field is 280 ft.