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In the 2018 infill development campaign, improved production was targeted by the operator through the installation of Autonomous Inflow Control Devices (AICDs) in a horizontal well at Offshore China. However, as the well requires gravel packing to manage the sand, the integration of AICD and gravel pack was an issue. The well was expected to intersect heterogeneous formations with varying properties resulting in an uneven reservoir influx toward the wellbore. In addition, water mobility in the reservoir is at least 150 times bigger than oil mobility and a strong aquifer is located near the well. Therefore, similar to the analogue wells completed with gravel packs, oil production from this well was expected to suffer severely from an early water breakthrough in a couple of weeks. These challenges can be mitigated by deploying AICDs that can manage the reservoir fluid influx toward the wellbore and therefore optimise the well performance. AICD, an active flow control device, delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through.
An integrated workflow was followed to deliver successfully the AICD application for CNOOC in an offshore heavy oil reservoir with huge uncertainties in remaining oil thickness and water-oil contacts. The well with the horizontal length of 440m was drilled in a thin formation with the oil column of 4.5m on average. The well intersected three different geological layers with different rock properties. The lower well completions comprised gravel pack, sand screens and RCP AICD valves were connected to an ESP pump lifting the fluids to the surface. The well was segmented in 4 compartments and a tailored AICD completions based on the real-time log data from the well was designed to properly restrict the production of unwanted fluid. Through teamwork between the companies, the well was successfully completed with AICD and gravel pack.
The final modelling was performed just in the time span between reaching target depth and running the completion. Over a period of 12 months production, the offset well with no AICD devices encountered water production in the first two weeks and water cut has kept increasing to 88%. However, the AICD well not only has no problem in terms of sand production and has limited water cut to less than 15% but also has successfully delivered 200% increase in total oil production compared to the offset well.
This well is an example that demonstrates the possibility of a successful combination of AICD and gravel packs. AICD completions ensured a balanced contribution from all reservoir sections and limited water production significantly while gravel pack kept the valves safe from impacts of sands.
Africa (Sub-Sahara) United Hydrocarbon International finished drilling the Belanga North-1 exploration well located in Doba basin in southern Chad. The well was drilled to a total depth of 1392 m, and encountered three oil-bearing sand intervals--two in the targeted Upper Cretaceous "YO" sands and one in an untested shallower sand. United Hydrocarbon (100%) is the operator. Asia Pacific China National Offshore Oil Corporation discovered natural gas in the Qiongdongan basin, South China Sea. Well Lingshui 17-2--located in the east Lingshui sag portion of the basin at an average water depth of 1450 m--was drilled and completed to a depth of 3510 m. Lingshui 17-2 encountered a gas reservoir with a total thickness of approximately 55 m. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia.
Africa (Sub-Sahara) Marathon Oil has produced first gas from its Alba B3 compression platform offshore Equatorial Guinea. The startup enables the company to convert approximately 130 million BOE of proved undeveloped reserves, which more than doubles its remaining proved developed reserve base in the country. Marathon holds an operating interest of about 65% in the field, with Noble Energy holding the remaining stake. Aminex said that gas production from the Kiliwani North-1 well in Tanzania has reached 30 MMcf/D (about 5,000 BOE/D). The project's commissioning process is expected to conclude with a well test to determine the optimal production rate, which previous test data suggest will be approximately 30 MMcf/D, the company said. The operator of the Kiliwani North Development License, Aminex holds a 54.575% interest in the well. Asia Pacific Beach Energy produced first gas from the Udacha field in Production Retention License 26 of the Cooper Basin in South Australia.
Carbon dioxide (CO2) waterless fracturing uses liquid CO2 to replace water as the fracturing fluid in reservoir stimulation. The continuity and reliability of the blender are key factors determining performance of the operation. Several well-stimulation products and techniques have been seen to benefit well productivity from recent field trials and implementations in carbonate reservoirs, including simpler acid fluid systems, integrated work flows, and coiled-tubing bottomhole assemblies. The complete paper discusses a method of stimulating deep, high-temperature offshore wells by combining an efficient single-phase retarded acid (SPRA) system and an engineered, degradable, large-sized particulate and fiber-laden diverter (LPFD). The complete paper discusses an advanced matrix-stimulation work flow that brings reliability and flexibility to the acidizing of tight carbonate water injectors and has delivered injectivity improvements tight carbonate onshore reservoirs in the Middle East.
ExxonMobil is reluctant to join other big oil companies writing down the value of their reserves. It could chop its reserves by 20%, but it has not made a final decision. Its reward for years of struggling to adapt to low prices and weak demand for its oil and gas has been an epic crash. Canadians selling change say it is time to consider possibilities that seemed inconceivable in the past. So many unprecedented changes have occurred in the Canadian oil business that it is impossible to compare the current downturn to anything seen before.
One of the frustrating aspects of well-productivity analysis is identifying the causes of lower-than-expected production/injection during initial well lifetime. Our task is to evaluate the multivariate aspects of well design. Wells in deepwater reservoirs show significant rate decline with time as the result of various causes. A diagnostic tool for quantification of factors influencing well-productivity decline is presented in this paper. The success of water-conformance operations often depends on clear identification of the water-production mechanism.
Satti, Rajani (Baker Hughes) | Bale, Derek (Baker Hughes) | Patel, Amar (Baker Hughes) | Nazarenko, Pavel (Baker Hughes) | Avella, Oscar (Baker Hughes) | Solorzano, Pedro (Ecopetrol) | Sanchez, Walter (Ecopetrol) | Giosa, Carlos (Ecopetrol) | Satizabal, Monica (Ecopetrol) | Vega, Sandra (Ecopetrol) | Hernandez, Nini (Ecopetrol) | Coronel, Ivan (Ecopetrol)
Injector well completions are typically carried out using two methods: simple and selective. The performance of injector wells has traditionally been evaluated using spinner-based injection logging tools (ILTs) or on-demand fiber optic distributed temperature and acoustic (DTS or DAS) sensing while logging the well performance every 3 months or once a year depending on the application. However, with such methods utilizing a snap shot approach, critical well performance information or possible anomalies are often missed due to measurements taken only during certain periods. Therefore, operators have explored the use of advanced fiber-optics methods such as permanent distributed temperature sensing (DTS) and permanent distributed acoustic sensing (DAS), that provide continuous, real-time measurements to enable understanding of dynamic well behavior at all times and mitigate any deferred or behavioral problems.
Of relevance to this work is a vertical, injector well in a competent sandstone formation of the Heavy Oil Chichimene field in Llanos Basin, Colombia. As a first step of the fiber-optics monitoring strategy, a careful evaluation of DTS and DAS based fiber-optics methods was conducted. Based on the data analysis and operational history, DAS-based fiber optics monitoring was chosen as the most effective monitoring solution for this well. Subsequently, a proprietary DAS algorithm was developed to analyze the data and estimate the flow allocation for all the four zones. The results include waterfall acoustic energy maps, temporal flow allocation profiles and most importantly, the zonal flow allocation values.
Predicted (DAS) zonal flow allocation data was compared with traditional injection logs (ILT) under different operational conditions (varied injection flow rates and valve choke settings). Based on comparable agreement between DAS and ILT data, the operator decided to replace ILT runs with DAS-based fiber optic monitoring, resulting in lower operational costs while enabling near real-time monitoring, and providing the continuous distributed data essential for the dynamic monitoring of the well. The successful application of fiber-optics monitoring to provide an injection profile in conjunction with a surface-controlled electric valve system demonstrates a significant potential to optimize the injection process in complex injector wells. Further, remotely controlling, monitoring and optimizing injection rates into the multi-segmented zones improves the service life of the injection operations, eliminates future intervention costs, and increases ultimate recovery.
Guerrero, Ximena (Schlumberger) | Medina, Daniel Ricardo (Schlumberger) | Munoz, Alberto (Hocol S.A.) | Rubiano, Jhon (Hocol S.A.) | Bejarano, Alied (Hocol S.A.) | Trujillo, Hernando (Hocol S.A.) | Saltel, Nicolas (Schlumberger) | Trillos, Julian (Schlumberger) | Becerra, Jerson (Schlumberger) | Castellanos, Diego (Hocol S.A.) | Coronado, Cesar (Hocol S.A.)
This paper describes the design, planning, and successful installation of a fit-for-purpose casing patch to isolate a water producing zone, the subsequent perforation of an adjacent zone, and a gravel pack completion in the same well for the first time worldwide. The proximity of the zones and the sand control requirements made the design and planning of this job a challenging task that is detailed in this manuscript.
The main producing zone in the SW-21 well watered out after few years of production. A second target was identified located just four feet below the main zone. To extend the life of the well and to add reserves from the secondary target, the upper 100% water zone had to be isolated. A fit-for-purpose, thin wall casing patch solution was designed to: allow perforation of the secondary target while maintaining patch integrity, allowing for the installation of sand control screens; and resist following gravel pack completion, by keeping the minimum recommended clearance between casing and screens, inside the minimal patch-reduced diameter.
The re-completions program consisted of: 1. Successful recovery of existing gravel pack from the main producing zone and thorough wellbore cleanup. 2. Casing patch installation consisting of a 23-ft long patch to isolate the water-producing zone. In this case, a specific engineering design analysis was required to ensure that, because of the very close distances between zones, the patch would still maintain integrity during perforation of the secondary target and the resulting patch overlap. 3. Successful integrity test to confirm upper interval isolation before perforating the lower interval. 4. A precise perforating operation carried out to perforate the secondary zone. Based on engineering recommendations, some length of the installed patch was perforated to guarantee a minimum unperforated distance of casing patch between zones to guarantee patch sealing features. 5. Once perforation was successfully accomplished, a gravel pack completion—inside the casing patch reduced diameter—was executed along the new zone for sand control purposes, and the well was put into production.
This paper presents the different interactions between a multidisciplinary research and development team, and completions and reservoir engineers to come up with a full solution for water isolation and sand control under such challenging conditions. For the first time in the world, a casing patch was used to isolate a water zone, and at the same time, perform a gravel pack completion inside the patch reduced diameter. Well performance, without any mechanical issues, confirms the success of the provided solution.
Africa (Sub-Sahara) Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D. Total operates the field with 24% interest, in partnership with NNPC, CNOOC, SAPETRO, and Petrobras.
We encourage you to take advantage of the technical programming and networking opportunities that these co-located events offer. Fawaz Bitar, IOGP Chairman, will present the IOGP Young Professionals Award. The Executive Plenary session will bring together industry executives and leaders to discuss their perspectives on the region???s foremost challenges and opportunities. A special emphasis on the interdependency between sustainable development and technology advancement will provide the audience with actionable insights to support regional and global growth efforts.A special emphasis on the interdependency between sustainable development and technology advancement will provide the audience with actionable insights to support regional and global growth efforts, intersecting touch points on how organizations are adapting and aiming to thrive with the wake of COVID-19. The opening panel session at LACPEC will focus on technologies and field operations that improve asset development in unconventional plays.