Baharuddin, Saira Bannu (Petroliam Nasional Berhad, PETRONAS) | Khair, Hani Abul (Petroliam Nasional Berhad, PETRONAS) | Bekti, Reza Amarullah (CGG) | Ali, Amita Mohd (Petroliam Nasional Berhad, PETRONAS) | Kantaatmadja, Budi (Petroliam Nasional Berhad, PETRONAS) | Som, Mohd Rapi Muhammad (Petroliam Nasional Berhad, PETRONAS) | Sedaralit, Faizal (Petroliam Nasional Berhad, PETRONAS)
Bioturbated zones are frequently bypassed by oil and gas operating companies during perforation due to the perception that they are nonproductive. We analysed data from wells in four fields in the Sarawak Basin, Malaysia, for selected bioturbated zones. The study included thin section, probe-permeameter, petrophysical, and routine core analysis. A bioturbation index classification scheme was established to allow semi-quantitative ranking for each foot of core. In the current study, we introduce a simulation script to predict lithofacies types at well locations based on input from bioturbation intensity algorithm (Ali et al., 2016), this script can be used for application on shallow marine field within Malaysia. We also used post stack seismic inversion for acoustic impedance and it proved to be a key approach to enhance the ability of predicting rock properties between wells. We generated a seismic derived lithofacies which provided the best estimate of lithofacies distribution between wells even though a well derived lithofacies had higher resolution. We calculated STOIIP using input from seismic lithofacies and porosity, and the results showed more accurate estimate of hydrocarbon in place compared with statistical approaches. Thus, the current seismic lithofacies methodology can be used for static model building and STOIIP calculation in shallow marine environments.
This paper is a subsurface introduction to the Hebron Field focusing on field discovery, delineation and development project history as well as geoscience and reservoir background. We will show how field understanding has evolved over time and how technology and data quality improvements impacted this project. For example, we will show how the recent IsoMetrix seismic survey has contributed to reservoir definition and architecture understanding. Finally, we will review the first drilling results after about six months into the drilling campaign.
The Hebron Offshore Development Project, offshore Eastern Canada, is one of the world's most ambitious oil projects. In November 2017 ExxonMobil Canada Properties (EMCP) commenced oil production from this world scale engineering marvel located in 93m of water approximately 350 kilometers southeast of St. John's NL in an area known as the Grand Banks.
The Hebron platform consists of a Gravity Based Structure (GBS) with a storage capacity of 1.2 million barrels of oil and an integrated steel topsides structure. The integrated topsides design with total operating weight capacity of ~65,000 t contains drilling and production facilities with a peak production capacity of 150,000 barrels per day (bpd) and a living quarters for 220 people. The field infrastructure also includes a subsea Offshore Loading System (OLS) providing crude offloading capability to tankers and a fiber optic cable loop linking the offshore platform to an onshore network enabling enhanced digital technology implementation. The project was sanctioned on 31 December 2012 and first oil occurred on 27 November 2017, ahead of schedule.
This paper discusses the Project from design through execution and highlights several of the unique design features, execution sequence and specific challenges which were faced. Special technologies were employed and project management initiatives implemented which enabled the success of the project.
The Hebron Project is the fourth major development offshore Newfoundland and Labrador, Canada, with an estimated 2620 million barrels of oil and a target first oil in 2017. The Ben Nevis reservoir accounts for approximately 80% of the crude oil with an estimated 30% recoverable. Hence, enhanced oil recovery (EOR) requires attention now even before production starts. This research evaluates the effectiveness of silicon dioxide (SiO2) nanoparticles as a water additive to enhance oil recovery in the Ben Nevis Formation, Hebron Field. The experiments involved two main steps: measuring interfacial tension, and determining the wetting character of the rock surfaces. Unlike previous research using SiO2 nanoparticles, in this work, the SiO2 nanoparticles are dispersed in seawater instead of deionized water or simple synthetic brine; experiments are conducted at reservoir conditions (Hebron Field: 62°C and 19.00 MPa); and synthetic cores were used that best represented facies of Ben Nevis Formation. A major challenge was forming a stable SiO2 nanofluid in North Atlantic seawater. Since salinity directly affected the stability of the nanofluid, hydrochloric acid was used as a stabilizer. Interfacial tension (IFT) was measured for SiO2 dispersed in deionized water, as well as stable nanofluids with SiO2 concentrations of 0.01, 0.03, and 0.05 wt% dispersed in seawater, to determine the contribution of SiO2 nanoparticle on the alteration of IFT. The contact angles were measured on core plugs before and after aging in 0.01, 0.03, and 0.05 wt% SiO2 nanofluids, to determine whether SiO2 nanoparticles can alter the wettability of the core. The results show that hydrophilic SiO2 nanoparticles are effective water additive for EOR. When comparing IFT experiments with deionized water and SiO2 nanoparticles dispersed in deionized water, the nanoparticles reduced the IFT from 39.70 mN/m to 21.54 mN/m. IFT is also reduced from 21.80 mN/m to 16.61 mN/m in case of experiments in seawater and a 0.05 wt% stable SiO2 nanoparticles dispersed in seawater. The contact angle experiments demonstrate that SiO2 can decrease the contact angle, and therefore make the rock surface more water wet under reservoir conditions. Finally, it is also found that the higher the SiO2 nanoparticle concentration, the higher the wettability alteration.
A detailed, fine-scale, reservoir characterization study of (light) tight oil rock intervals in the Cardium Formation is performed using an innovative combination of X-Ray CT Scan technology, hardness and profile (probe) permeability measurements. This study aims to quantify the geometry, degree of heterogeneity, and several other key properties, of individual microlithofacies within the highly bioturbated sandstone lithofacies.
Contrasting bulk density values between these microlithofacies domains is identified using X-ray CT-Scan imagery reconstruction. Statistical analysis yields numerical information regarding geometry and connectivity of individual bodies for a given microlithofacies within the analyzed volume. Permeability, as estimated from a profile (probe) permeameter, and hardness of the samples, as quantified using a hardness index (from Leeb Hardness measurements), is investigated for a sub-centimeter 2D grid on slabbed surfaces. This detailed mapping allows the analysis of mm- to cm-scale correlations between rock quality and CT images.
Identified microlithofacies include SS1 and SS2 (sandstones), SH1 (shale), and PB (pyrite-filled burrows). Permeability can exceed 50 mD in SS1 microlithofacies, but generally is less than 1 mD for SS2 and 0.01 mD for SH1. Volumetric reconstruction of these microlithofacies yields approximately 85% total sandstone content for an average sample from tight-oil Cardium lithofacies (which is higher than visual assessment of 50-60% sandstone). The sandstone ratio of SS2/SS1 is between 3 and 5; microlithofacies SH1 and PB have a patchy distribution through the core. SS1 appears as highly disturbed relics of very thinly bedded patches, and sandstone-filled, subhorizontally oriented, sub-centimeter scale burrows. Relatively higher values of bulk density and hardness index characterize SS2 and SH1 microlithofacies.
The overall low permeability usually measured in this lithofacies can be attributed to the complex interplay between biological and physical sedimentary structures at the cm-scale, generating more or less randomly connected volumes with contrasting flow and storage capacity. This study provides a roadmap for more accurate property measurements and modeling at the core scale for this complex lithofacies of the Cardium Formation; we believe that this will also be useful for other tight oil reservoirs.
Thomas, Brandon George (Husky Energy) | Iliyas, Abduljelil (Memorial University of Newfoundland and Labrador) | Johansen, Thormod Ekely (Memorial University of Newfoundland and Labrador) | Hawboldt, Kelly (Memorial University of Newfoundland and Labrador) | Khan, Faisal (Memorial University of Newfoundland and Labrador)
A consortium of university-industry researchers are developing sustainable and environmentally friendly enhanced oil recovery (EOR) technology for oil fields off the east coast of Newfoundland, Canada. This paper is foundational work on potential implementation of air and flue gas injection techniques. The paper discusses reservoir and facility considerations of air and flue gas injection and provides recommendations for project evaluation. The paper presents screening level results for Husky Energy's White Rose Field as a case study.
Newfoundland offshore fields contain light oil (30-37 oAPI, 0.5-0.8 cP) making the fields potential targets for gas based EOR. However, with the oil fields located 310-350 km off the coast, availability of injection gas and logistical problems present barriers to EOR. Air injection has the advantages of an unlimited supply of injectant, success in laboratory and field applications, years of safe operation, and potential for an estimated 10% incremental oil recovery in waterflooded reservoirs. The challenges toward implementation of both techniques considering field characteristics and infrastructure are discussed along with practical solutions to aid implementation.
The evaluation of sustainable and environmentally friendly EOR technologies is inline with long-term regulatory requirement and is timely as oil production from existing fields is beginning to decline. Moreover, with only 3 of over 20 discovered fields off the coast of Newfoundland currently developed, the conclusions and recommendations may also be valuable in the near future for evaluation of EOR techniques for the remote fields offshore Newfoundland.
Understanding reservoir compartmentalization is one of the key aspects of effective reservoir management. The optimization of production and injection wells is a key objective of this process. Integration of seismic, formation tester and other data along with production results, provides valuable information about reservoir compartmentalization.
This data integration concept was applied to characterize reservoir connectivity in the central development region of the White Rose Field. The reservoir interval consists of a thick Cretaceous-aged sandstone reservoir (Ben Nevis formation) located offshore Newfoundland, Canada. The field development strategy involves drilling horizontal producers and a combination of deviated and horizontal injectors. Production/injection began before drilling of all wells in the field, leading to drilling under dynamic conditions in a field that achieved oil production rates in excess of 135,000 bbl/d.
Prior to production, the White Rose Field appeared relatively homogeneous with well-connected flow units, although reservoir heterogeneity and fault compartmentalization were considered the greatest risks to recovery. Subsequent dynamic multi-disciplinary data obtained during production highlights specific intervals of compartmentalization allowing for a focused approach in dealing with heterogeneous flow. Formation pressure while drilling (FPWD) data, acquired in newly drilled horizontal or deviated wells, indicate complex flow paths between injector and producer. A combination of pressure data from multiple wells, petrophysical interpretations, geophysical analysis, and production data, provides important information about reservoir connectivity and the transmission properties of several faults.
This paper describes how an integrated approach, along with the implementation of new technology measurements, facilitated effective reservoir management. The integration of the data to transform the pre-production reservoir characterization into a syn-production simulation model is elaborated upon. The discussion also addresses the sealing nature of the faults and vertical barriers to flow. The process has been useful in managing the production and injection wells, as well as determining the drilling requirements for infill wells.
Twenty-four oil and/or gas discoveries have been made offshore Newfoundland and Labrador. Three of the oil discoveries have been developed and a fourth is under consideration. The focus of development activity has been on the larger oil discoveries. As production from the larger discoveries matures, facilities and other infrastructure will become available for development of the remaining smaller discoveries. Development and tie-in of smaller pools and fields provides an opportunity to utilize this spare production capacity at these fields. Currently, there are several satellite tie-in and expansion projects in progress and others are under review. Development of the discovered smaller fields will play an important part in sustaining production from offshore Newfoundland and Labrador. In addition, many of the offshore basins are under explored and represent other opportunities to supply the next round of developments.
Newfoundland and Labrador, Canada's easterly province (Fig. 1) is strategically positioned on international shipping lanes, with unique access to global petroleum markets.
Pressure measurement plays a critical role in the development and management of compartmentalized reservoirs. Conventionally, pressure data have been recorded using wireline formation tester (WFT) tools. In highly deviated or horizontal wells, wireline testers must be conveyed on drill-pipe at considerable expense and often with operational risk and limitations.
To reduce operational risk and costs of long reach directional drilling of the Hibernia Field, offshore Newfoundland, a new generation formation pressure while drilling (FPWD) tool was deployed. To confirm the capability of acquiring quality pressures with mud-pulse based telemetry, the conventional wireline formation tester tool and the FPWD were run in the same well.
The pressure and mobility data recorded with the FPWD tool and wireline formation tester tool matched within 1 psi and with a fluid gradient difference of less than 0.004 psi/ft. Twenty-one successful tests were acquired in rocks with mobility ranging from 4 to 1100 md/cp. A pre-set testing sequence that never exceeded 15 minutes of stationary time was used. Seal integrity and tight tests could be readily identified from 6-bits per second mud-pulse telemetry. In addition to comparing pressure measurements, the FPWD tool was run both while circulating mud and with the pumps off. Although the pumps on test did introduce a fine scale noise, the pressure and mobility data collected were identical.
LWD and wireline pressure data were both collected in a second Hibernia well when the FPWD tool failed to seal with the formation after the fourth pressure measurement. These four pressure points repeated precisely when measured subsequently with wireline technology. The probe filter, which was the cause of the failure in the previous tests, was redesigned and several subsequent runs have been successfully completed at Hibernia with a 100% seal success. FPWD technology is now the preferred deployment mode when unassisted wireline runs are not possible.