The negative impacts of high water cut in mature fields are well known within the oil & gas industry. Water production preventive & mitigative measures are well established and documented: Wireline or coil tubing conveyed diagnostic and work-over operation(s) is one of such common preventive measures. This paper, through a series of integrated case studies will highlight the best practices for wireline conveyed logging and work-overs with one common goal, i.e. to achieve the water production to a minimum acceptable level in deviated high water cut wells.
The prolific XYZ field is located in the Northern North Sea and it produces oil from Jurassic Brent Group. Oil production from the XYZ reservoir started in early 1978, with 43 producing wells and 15 water injection wells targeting the Rannoch, Etive, Ness and Tarbert sands. Oil and gas production peaked in 1982 and since then production has steadily declined for this field. The increasing water cut in the wells of this field is presenting a challenge for the operating companies.
Production profiling using advanced Production Logging data, casing/tubing integrity check using Multi-Finger Caliper data and saturation monitoring using cased-hole Reservoir Saturation data was done in these wells to ascertain the water producing zones and do the subsequent well intervention, if required. A strategic diagnostic test was designed to precisely evaluate the flow profile using advance production logging tool consisting of 5 mini-spinners & 6 sets of each electrical and optical probes; Real-time data assessment and analysis was done for different flowing rate surveys to validate the findings. Additionally, casing condition was evaluated using Multi-Finger Caliper to decide Plug or Straddle setting depths. Also, new hydrocarbon bearing zones were identified based on cased-hole saturation tool results. The analysis results boosted the cumulative oil production.
This study demonstrates the importance of making real time interpretation decisions at the wellsite and the benefit of developing a good working relationship between wellsite engineers and onshore technical support. The results of this work led to the unequivocal determination of major oil and water producing zones in deviated high water cut (95%+) wellbores which further helped in taking workover decisions to carry out water shut off, utilizing either plug or straddle technology. The findings of caliper data determined the appropriate plug or straddle setting depths. The results were compared and confirmed with the nearby well dynamic pressures and production data.
The technical approach and processes applied to wells of XYZ field is a valuable example guide to decide water shut off zones and technique of similar plays. This study consists of three integrated case studies from a mature field where water shut-off zones and technologies were decided based on the findings of production logging and well integrity data. Also, re-perforation jobs were performed based on the cased-hole reservoir saturation data results. These strategic workover operations ultimately led to significant increase in hydrocarbon production.
On the Vega gas condensate and oil field in the Norwegian North Sea, two high temperature, high pressure (HTHP) gas condensate wells on one subsea template in 370 m water depth were acid and scale inhibitor treated in order to improve productivity by acid scale removal and prevent future scaling. Significant amount of work was undertaken on design and qualification of the treatment fluids. In order to reduce operation time and increase efficiency, a novel one-time connection concept was utilized. During the operations, wells were kicked off after energizing with gas bullheaded from the neighbouring well. The treatment fluids were designed to reduce consequences for the host facility due to H2S generated during the operation - this required optimization after understanding of the H2S source as witnessed in prior treatments.
The new concept with one-time connection was successfully employed and allowed for three subsequent well treatments in a row, thus saving at least two days vessel operations time. The gas injection from the neighbouring well - the one not treated at the moment - allowed for an efficient start-up of the treated well without need for larger nitrogen injection which would have led to contamination and potentially to flaring due to off-spec gas. The introduction of a batch with pH neutralizer and H2S scavenger batch into the treatment design to be placed into the production pipeline reduced H2S liberation and production to the host facilities, thus limiting the operational stress on the platform. Productivity of well A1 showed an immediately significant increase after the operations, whereas productivity of well A2 required a longer clean-up than originally anticipated.
Lu, Cong (Southwest Petroleum University) | Li, Junfeng (Southwest Petroleum University) | Luo, Yang (SINOPEC Southwest Oil & Gas field Company) | Chen, Chi (Southwest Petroleum University) | Xiao, Yongjun (Sichuan Changning Gas Development Co. Ltd) | Liu, Wang (Sichuan Changning Gas Development Co. Ltd) | Lu, Hongguang (Huayou Group Company Oilfied Chemistry Company of Southwest) | Guo, Jianchun (Southwest Petroleum University)
Temporary plugging during fracturing operation has become an efficient method to create complex fracture network in tight reservoirs with natural fractures. Accurate prediction of network propagation process plays a critical role in the plugging and fracturing parameters optimization. In this paper, the interaction between one single hydraulic fracture within temporary plugging segment and multiple natural fractures was simulated using a complex fracture development model. A new opening criterion for NF penetrated by non-orthogonal HF already was implemented to identify the dominate propagation direction of HF under plugging condition. Fracture displacements and induced stress field were determined by the three dimensional displacement discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by HF within plugging segment, HF tends to propagate along the relative upper part when the approaching angle is less than 90°, otherwise the lower part will be easier to open. The farther interaction position is away from HF tip, the easier NF with approaching angle less than 30° or larger than 150° can be open, and the outcome will be opposite if the approaching angle is larger than 45° or less than 135°. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the impact of plugging, fluid pressure in HF plummets at the beginning of NF opening and keeps decreasing until NF extending for a certain distance or encountering secondary NFs. Fluid pressure drop occurs mainly in the unturned NF, together with the width of unturned NF is significantly lower than that of turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid pressure distribution, affecting the network progress under temporary plugging condition are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging segment length. The simulation results provide critical insight into complex fracture propagation progress under temporary plugging condition, which should serve as guidelines for welling choosing and plugging optimization in temporary plugging fracturing.
Jin, Yan (China University of Petroleum at Beijing) | Jin, Guodong (Baker Hughes, a GE Company) | Syed, Shujath Ali (Baker Hughes, a GE Company) | Jin, Miao (China University of Petroleum at Beijing) | Hussaini, Syed Rizwanullah (King Fahd University of Petroleum and Minerals)
Subsurface unconventional shale samples are always scarce. Outcrop analogs are often used as an alternative to enhance the understanding of the corresponding reservoir formation. One assumption is usually made that rock composition and properties between the outcrop and subsurface samples remain the same or similar, despite differences in their burial and diagenetic histories. This paper presents a comparative case study to investigate the similarities and differences in rock properties between outcrop and subsurface samples from the same formation.
Two subsurface and two outcrop samples from the Lower Silurian Longmaxi formation in Sichuan Basin of China were characterized to determine their mineralogical, geochemical, petrophysical, elastic and mechanical properties. Micro-CT images showed that one subsurface sample was drilled normal to the bedding, while other three samples were parallel to the bedding. Two subsurface samples differ in their mineralogy – the horizontal sample is clay-dominant, while the other one is predominantly comprise of quartz, dolomite and calcite minerals, very similar to two outcrop samples. All four samples are thermally immature and their Tmax is less than 435 °C. Subsurface samples have the highest TOC of 3.75% but relatively lower HI and OI. Other pyrolysis parameters are very similar between subsurface and outcrop samples. All samples have very low porosity of less than 2.5% and permeability of less than 9 nD, although subsurface samples have a relatively higher value.
The discrepancy in mineralogical composition, especially the clay content, results in different elastic and mechanical behavior of outcrop and subsurface samples. The subsurface sample is highly anisotropic in both compressional and shear wave anisotropy due to the large amount of clay minerals, while one outcrop sample exhibits the strong shear wave anisotropy only and the other one is almost isotropic. Subsurface samples have lower values of Young's modulus, peak stress, Mohr-Coulomb failure parameters and unconfined compressive strength than outcrop samples.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Africa (Sub-Sahara) Kosmos Energy has made a significant deepwater gas discovery off Senegal. The Guembeul-1 well in the northern part of the St. Louis Offshore Profond license in 8,858 ft of water encountered 331 net ft of gas pay in two excellent-quality reservoirs, the company reported. The results demonstrate reservoir continuity and static pressure communication with the Tortue-1 well, which suggests a single gas accumulation. The mean gross resource estimate for the Greater Tortue complex has risen to 17 Tcf from 14 Tcf as a result of the Guembeul discovery, the company said. Kosmos, the operator, has a 60% interest in the well. Timis (30%) and Petrosen (10%) hold the remaining interest. In Salah Gas has started production from its Southern fields in Algeria.
Well Placement encompasses the engineering and services required to spatially place all our well types in the optimal position with respect to current and future value creation. It is paramount that this placement firstly considers HSE with respect to existing wells, geohazards and our understanding of the pore-pressure/fracture gradient regime (well control). With this is mind Well Placement needs to apply a risk based multi-disciplinary approach. This session will cover the optimisation of survey acquisition and advanced quality control of existing systems, and also present the latest thinking with respect to trajectory definition and technology advancement.
Ruoff, Matthijs (Oranje-Nassau Energie B.V.) | Costa, Driss (Oranje-Nassau Energie B.V.) | Rosenberg, Steven (Weatherford) | Ameen, Sayamik (Weatherford) | Krol, Dariusz Krol (Weatherford) | Salomonsen, Halvard (Weatherford) | Tan, Ming Zo (Weatherford)
While drilling through the Permian Zechstein Group, North Sea operators can encounter a permeable overpressured interval which cannot be statically stabilized with conventional methods. An operator proposed drilling with Liner (DwL) in combination with managed pressure drilling (MPD) and continuous circulation technologies as a potential solution to this drilling hazard. In case that the overpressured interval was not seen, the DwL BHA could be retrieved after which the remaining section would be drilled conventionally. The DwL process allows a hazardous interval to be isolated in a single trip resulting in less risk and exposure compared with conventional drilling methods. Realizing the potential benefits automation brings, many operators have turned to MPD techniques as a technical and cost-rewarding solution to hard-to-reach assets, an approach which not only saves time but also enhances the safety capabilities of the operation. More importantly, MPD is increasingly being considered for other operations requiring precise pressure control to maintain wellbore integrity in constricted drilling envelopes. Continuous circulation technology provides a method to ensure continuous flow downhole while making connections which supplements the controlled annular pressure profile to avoid a drilling fluid / formation fluid change out. The prompt collaboration within the operator-service provider team determined which combination of these technologies would be the safest and most effective means for managing the overpressured interval should it be encountered.
This collaborative effort consisted of well engineering analysis and risk assessment sessions to ensure that the 12 ¼-in. hole objectives could be met in a safe and efficient manner aligning with the overall well objectives. The analyses included DwL, MPD, continuous circulation procedures and related simulation modelling for the running, drilling and cementation of the 9-5/8-in. × 13-3/8-in. liner. The combined technologies encompass a multitude of engineering disciplines; these were integrated into the operator's drilling plan in a seamless manner. Potential concerns and drilling hazards were identified and reduced to a manageable level. Ultimately, the 9-5/8-in. DwL system was used without encountering the overpressured interval and therefore the DwL BHA was retrieved with the remaining 12-1/4-in. hole interval conventionally drilled to planned depth without incidents. This paper will illustrate inclusion of DwL, MPD and continuous circulation technologies in the drilling plan as an effective solution for the mitigation of hazardous intervals. It will also reinforce the value of a close working relationship between operator and integrated service providers to eliminate uncertainties and provide sufficient risk mitigation to ensure that intended well objectives will be met.
To improve magnetic disturbance rejection and robustness of wellbore survey measurements, an adaptive neuro network-based fuzzy inference system (ANFIS) filter for wellbore position calculation is presented. This technique significantly improves magnetic disturbance rejection and reduces sensor error influence for borehole survey measurements. The new approach for the ANFIS filter is based on two redundant sets of IMUs which are located in different positions in the BHA at a known, constant distance. The distance between these two sets of IMUs will physically fade the effect of the magnetic disturbances. Each IMU set outputs position estimation based on the splines method which is then input into an ANFIS filter. The inputs of the splines calculation are azimuth, inclination angles and measurement depth, and the outputs are moving distance in three directions (Northing, Easting and True Vertical Depth). However, the accuracy of the splines method highly depends on the accuracy of the inputs, which are difficult to obtain during the measurement while drilling process even under pure clean environments (without any magnetic disturbances). Furthermore, the distorted azimuth caused by magnetic interference affects the borehole position accuracy. In order to deal with those problems, the designed ANFIS filter has a two-level structure. First a local level position estimation (splines method or well trained local ANFIS based on the sensor accuracy) for two sensor sets is used. If the sensor measurement accuracy is low, this local ANFIS will correct the position estimation. Then the outputs of the local modules were input into ANFIS for second level filtering (global filter) to remove the error which caused by unknown magnetic disturbances. According to the judgement of the ANFIS, the IMU set with the smaller magnetic disturbance is given greater weight to reduce the interference effect on the borehole position estimation. This two-level filter is compared to the traditional splines method under different tests situations. First, we evaluate this method by comparing with GPS positioning, from this test we know that the ANFIS filter shows a good performance when the magnitude of magnetic disturbance is within the training magnitude range. Even when the magnitude of magnetic disturbance is above the training range, the ANFIS filter shows a higher robustness than the traditional splines method. Also, this method was applied to borehole data with two IMU containing accelerometers and one magnetometer measurements. In order to apply our method, we duplicated one more magnetometer measurement data under magnetic interference for assessment. The results proved its magnetic disturbance robustness in borehole position estimation. Finally, we demonstrate the full potential using a laboratory experimental setup.
The IADC and SPE are committed to delivering a balanced agenda around Diversity and Inclusion, to support member companies as they strive to address the gap in the Oil & Gas Sector. In 2019 the SPE/IADC International Drilling Conference and Exhibition in The Hague will host a session that allows delegates to explore the challenges facing the industry and hear firsthand, how it can be addressed. This initiative aims to build on the efforts already being undertaken at individual company levels to attract, develop and retain female staff - especially in technical and senior management roles, and to remove barriers that may currently hinder or discourage women from rising through the ranks into leadership roles. The aim is to address the factors contributing to the gender gap and to advantage all companies, their owners and shareholders through the incremental performance and value that parity will generate. This is good for our people, good for our stakeholders, and good for our business. Whilst in 2017 the session focused on subjects arising from DAVOS 2016 namely Leadership, Aspiration, goal setting, STEM, recruitment and retention, corporate culture and work life balance, the panel now feel it is time to move the conversation forward with some hard-hitting topics that affect the lives of many. Make sure you join us for this special session in The Hague.