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Celtic Sea
Abstract This paper describes the application of machine-learning techniques for unlocking the full potential of nuclear magnetic resonance (NMR), using a case study from the Seven Heads gas field. This field has long been recognized but was not developed due to a variety of technical challenges, including the thin-bedded nature of the sediments and the presence of both mobile and immobile viscous residual oil. The oil is a highly viscous liquid which, if produced, could block production tubing due to the shallow depth of the reservoir and associated low pressures. To produce dry gas successfully, identification of both oil and gas zones was necessary to enable gas zones to be perforated and oil zones to be excluded. During the development drilling campaign, the reservoir was appraised using a formation evaluation program specifically designed to address the presence of oil within the thinly bedded reservoir. In conjunction with core data and high-resolution electric logs, NMR logs were used to identify and avoid perforating zones with higher oil saturations. Formation fluid types were derived from the NMR using a pattern recognition technique that analyzes the entire shape of the T1 and T2 distributions to derive the volumes of gas, oil, and water. This machine-learning technique was calibrated using Dean and Stark fluid analysis data and enabled the prediction of continuous water, gas, and oil saturation curves. The results were used to ensure that the perforation strategy avoided oil-bearing sands. This paper describes how the NMR, together with machine learning, has enabled a complex tight gas field to be developed.
annual logging symposium, application, Artificial Intelligence, case study, Cuddy, evolutionary algorithm, expert system, full potential, fuzzy possibility, gas field, june 2022, log analysis, machine learning, NMR, prediction, reservoir, saturation, transaction, unlocking, Upstream Oil & Gas, well logging
Country:
- North America > United States > Texas (0.68)
- Europe > Ireland > Celtic Sea > County Cork > Celtic Sea (0.24)
Oilfield Places:
- Europe > Norway > Norwegian Sea (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 49/21 > Kinsale Field > Seven Heads Field (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 49/16 > Kinsale Field > Seven Heads Field (0.99)
- (4 more...)
SPE Disciplines:
Technology:
- Information Technology > Artificial Intelligence > Machine Learning > Evolutionary Systems (0.47)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Expert Systems (0.47)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Rule-Based Reasoning (0.46)
Abstract The Kinsale Head gas field offshore Ireland was discovered in 1971 and bought on stream in 1978. After 40 years of continuous gas production, a detailed plan for decommissioning of the field facilities is now being implemented. Kinsale Head and a number of satellite gas fields, all operated by PETRONAS subsidiary PSE Kinsale Energy Limited, are the only producing facilities in the North Celtic Sea Basin, off the south coast of Ireland. The facilities include two fixed platforms, 10 subsea wells and extensive subsea infrastructure including 150 km of subsea pipelines and 80 km of subsea umbilicals, as well as an onshore reception terminal. Careful and innovative field management has extended the producing life from an originally estimated 20 years to over 42 years at time of Cessation of Production forecast to occur in 2020. The paper describes some of the methods used to prolong field operating life. Planning for decommissioning commenced in 2015-2016 and the paper describes the engineering and regulatory planning process followed. As this is the first-offshore field to be decommissioned in Ireland, extensive and detailed engagement with the regulatory authorities was undertaken prior to the submission of the decommissioning plan in 2018. The paper demonstrates how a systematic and logical approach to both the regulatory approval process and the physical execution plan helps to de-risk the project. In particular, a comprehensive Environmental Impact Assessment (EIA) process was followed to underpin the selected strategy and to demonstrate a ‘best-in-class’ approach to the decommissioning program. As part of the EIA process, a number of analytical techniques were used including Net Environmental Benefits Analysis (NEBA) and Comparative Assessment (CA); this is believed to be the first time these techniques were used for offshore projects in Ireland.
Artificial Intelligence, comparative assessment, decommissioning planning, Directive, Disposal, environmental impact assessment, identification, information, Ireland, kinsale energy, kinsale head gas field, offshore pipeline, operation, platform, project management, protection material, requirement, social impact assessment, social responsibility, spe-199173-m, stakeholder, strategic planning and management, subsea system, sustainability, Upstream Oil & Gas, US government
Industry:
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.89)
Oilfield Places:
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 49/21 > Kinsale Field > Kinsale Head Field (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 49/16 > Kinsale Field > Kinsale Head Field (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 48/25 > Kinsale Field > Kinsale Head Field (0.99)
- (2 more...)
SPE Disciplines:
Abstract Frontier Exploration Licence 7/97 is located 115km offshore north-west Ireland and directly overlies the Erris Ridge. The ridge is an enigmatic, narrow, segmented, NE-SW orientated structural high which lies between the Erris Basin to the east and the Irish Rockall Trough to the west and which, to date, remains un-drilled. Seismic data quality across the Erris Ridge is typically poor and correlation with the sparse offset well database is challenging. Zones of poor seismic imaging are associated with combinations of complex shallow volcaniclastics, possible intrusive features and large-scale Tertiary channels/entry points which overlie older strike-slip zones and segment the ridge along its length. Displaying considerable complexity and structural variation along strike, seismic based interpretations provide models ranging from a shallow basement horst to preservation of significant thicknesses of Paleozoic and Mesozoic sediments. Recent work by Eni identifies the potential for prospective section to be preserved on the Erris Ridge resulting in two large prospects, Fiachra and Conn, and a number of leads being identified. The Fiachra Prospect is a large fault assisted four-way dip closure situated within a crestal location on the Erris Ridge and forms the focus of an exploration well planned for 2010. An early Triassic sandstone play (Sherwood Sandstone Group equivalent) is prognosed as the primary reservoir target interval, although several secondary targets also exist. After an intensive evaluation programme the critical geological risk remains modelling the presence of sedimentary section with reservoir potential in areas where the quality of seismic data is very poor. However, it is concluded that Licence 7/97 possesses good potential for deepwater frontier exploration; the Corrib gas field to the south of the licence area and the Dooish gas discovery to the north indicate the potential for a favourable location within an effective petroleum system. Introduction Frontier Exploration Licence (FEL) 7/97 is located on the Irish Atlantic Margin, approximately 115km offshore northwest of Ireland in water depths spanning 200m to 2000m (Figure 1). The licence extends over eight blocks; 11/20, 11/23 (part), 11/24, 11/25, 11/28 (part), 12/11 (part), 12/12 (part), and 12/16 (part), covering an area of 1327.66km and is located over the NE-SW trending Erris Ridge which separates the Rockall Trough to the west from the Erris Basin to the east. Eni acquired full operatorship of FEL 7/97 in 2001 and has since undertaken an extensive evaluation programme in order to assess the prospectivity of the licence area and support the decision to commit to the drilling of a frontier exploration well on the Fiachra prospect. Accordingly, the prime focus of exploration activity has centred on the Erris Ridge and, in particular, the maturation of the Fiachra prospect. Critical factors determining prospectivity across the Erris Ridge are related to structural evolution and the age and thickness of potential reservoir quality stratigraphic section preserved across the poorly imaged central region of the ridge, both of which have been subjects of discussion (e.g. Cunningham and Shannon, 1997; Chapman et al., 1999). This uncertainty is difficult to address through conventional seismic acquisition as a result of poor data quality predominantly influenced by shallow, indurated, Paleogene volcaniclastic deposits which are widespread within the licence area.
basin, data quality, Erris Basin, Erris Ridge, fel 7 97, Ireland, irish atlantic margin, licence area, Petroleum Geology, prospect, Reservoir Characterization, Rockall Basin, rockall margin, Rockall Trough, sandstone, sedimentary section, seismic data, sequence, Slyne basin, structural geology, Upstream Oil & Gas
Country:
- Europe > Ireland > County Mayo > Slyne Trough > North Atlantic Ocean (0.34)
- Europe > Ireland > Celtic Sea > County Cork > Celtic Sea (0.28)
- North America > United States > Kentucky > Butler County (0.24)
Geologic Time:
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Mesozoic > Triassic (1.00)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- (4 more...)
Geophysics:
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
Oilfield Places:
- Europe > United Kingdom > England > Southern England > Weald Basin (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Rockall Basin (0.99)
- Europe > Norway > Norwegian Sea > Vøring Basin (0.99)
- (23 more...)
SPE Disciplines:
Summary Early, accurate determination of original gas in place (OGIP) is highly desirable for planning the future of a gas field. This paper presents a case history of an offshore gas field, using a recently developed pressure-rate-time analysis technique to illustrate the effectiveness of the method. In addition, this paper demonstrates the great benefit of permanently installed pressure gauges in obtaining consistent pressure and flow-rate data for the effective use of the technique for subsea completed wells. Introduction Early, accurate determination of OGIP is always desirable in a new gas field development, as this information is critical in decision making for reservoir management. For example, the optimum number of wells or the need for compression at the surface depends on OGIP. In addition, the operator is often required to project production rates in order to secure a gas sales contract. These decisions are typically made early in the life of a field, and erroneous estimates of OGIP can lead to poor decisions that may be costly or impossible to correct later in the field life. Various reserve estimation methods have been published in the literature, ranging from basic material-balance calculation to decline-curve analysis. Recently, Agarwal et al. presented new production decline curves for analyzing well production data by combining type-curve and decline-curve analysis concepts. In this report, we applied Agarwal et al.'s analysis techniques to pressure and rate measurements over a period of approximately 3,000 days at Ballycotton. Subsequent analysis of short-term performance data showed that an accurate estimate of OGIP was established from the first 6 months of production. The results were confirmed independently using reservoir simulation while examining the effects of water influx and production interference from Kinsale Head. Background Information Geologic Setting and Field Description. The Ballycotton gas field lies approximately 25 miles off the coast of Cork, Ireland in the North Celtic Sea basin. It was discovered in March 1989 and has been produced from Well 48/20-2 since July 1991 as a satellite field by means of a single subsea well completion and tieback to the Kinsale Head's Bravo platform. A location map is shown in Fig. 1. The ‘A’ Sand producing interval in Ballycotton and Kinsale Head is the focus of this paper. This sand extends from Kinsale Head gas field in the south to Ballycotton gas field in the north, thus connecting the two fields by a common aquifer. Ref. 3 gives a comprehensive geologic description of the region. The Kinsale Head gas field was discovered in 1971 and was placed on production in October 1978. The existence of gas-processing facilities at Kinsale Head made it commercially feasible to produce Ballycotton, which at the time of discovery was thought to contain 80 Bcf from a volumetric study. About 760 Bcf of gas were produced from the ‘A’ Sand of Kinsale Head by the time Ballycotton was placed on-line. Immediately after Ballycotton was put on production in July 1991, an attempt was made to estimate OGIP from the initial production data. Assuming hydrostatic equilibrium between the two fields, the initial pressure at Ballycotton was estimated from 1978 pressures at Kinsale Head gas field. This pressure, compared to the Ballycotton pressure measured immediately before commercial production, shows a pressure loss of 50 psi, thus reflecting interference resulting from production at Kinsale Head. Pressure interference is transmitted through the common aquifer between Kinsale Head and Ballycotton. Because the complexities of water influx and interference cannot be easily accounted for in a gas/water system, it was difficult to provide an OGIP estimate from the simple material balance. However, a numerical simulation study of a single well in an edge-waterdrive gas reservoir indicated that it was possible to estimate an OGIP from the drawdown data in the early life of a reservoir before the influence of water influx becomes dominant. Later, a full-field model was set up to examine the strength of water influx. This will be discussed in the simulation study section. The Ballycotton completion was the first subsea development in the Celtic Sea. A permanent gauge was installed on the subsea tree in 285 ft of water to monitor wellhead pressure (WHP). From the corresponding gas rate and measured WHP, we calculated bottomhole pressure (BHP) with the Cullender and Smith method.Fig. 2 shows a graph of calculated flowing BHP and gas-flow rate between July 1991 and September 1999. Both pressure and rate are monotonically decreasing. Our goal was to determine the OGIP from the production-performance data with both flowing BHP and gas-flow rate. Historical Development of Analysis Technique. Analysis of the gas-production performance data involves nonlinear effects of gas physical properties and variable-rate production mode during boundary-dominated flow. Recognizing that the partial-differential equation governing the flow of gases is nonlinear, researchers have focused on correlating the gas-flow solutions with the appropriate liquid-flow solutions. Gradually, a new time function was developed to convert the production data of either constant rate or constant BHP into a form that could be analyzed with constant-rate liquid solutions. This section presents the historical development of these techniques. To analyze monotonically declining rate and pressure data to estimate reserves, pseudosteady-state flow must be established in the long-term performance data. Using the principle of superposition, Blasingame and Lee showed that equivalent time, te, defined as cumulative production divided by the corresponding flow rate, could be applied to a liquid system in pseudosteady-state flow. This suggests that long-term performance data can be used to estimate pore volume by plotting the pressure difference (?=pi-pwf) normalized by the corresponding flow rate vs. te. The slope of the graph is used to calculate reserves for a slightly compressible liquid case. Al-Hussainy et al. showed that during the boundary-dominated flow period there are considerable differences between the liquid and gas solutions. It is clear that nonlinear effects become dominant during the pseudosteady-state flow period, when the wellbore pressure depends on the physical properties of the produced gas and the flow rate.
aquifer, average reservoir pressure, Ballycotton, cartesian analysis, Drillstem Testing, drillstem/well testing, estimates of resource in place, february 2001, field data, gas field, graph, interference, Kinsale Head, liquid solution, Modeling & Simulation, OGIP, performance data, production control, production data, production monitoring, pseudoequivalent time, pseudosteady-state flow, reserves evaluation, reservoir simulation, Reservoir Surveillance, resource in place estimate, SPE Reservoir Evaluation, Upstream Oil & Gas
Oilfield Places:
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (29 more...)
SPE Disciplines:
Abstract This paper presents a new approach for determining OGIP early in the field life of an edge-water drive gas reservoir. The approach is applied to Ballycotton gas accumulation. Ballycotton was discovered in March 1989 adjacent to the nearby Kinsale Head Field, a major gas accumulation in the Celtic Sea, Ireland. Ballycotton and Kinsale Head have a common aquifer. Kinsale Head Field was put on production in 1978 using two platforms Alpha and Bravo. From July 1991, Ballycotton produced gas as a subsea-completed satellite of the Kinsale Head Field, tied back to the Bravo platform at Kinsale Head. A permanent gauge was installed on the subsea tree in 285 feet of water. Using continuous pressure and rate measurements, we routinely interpreted well data using superposition techniques. Within the first six months of production, an accurate estimate of original gas-in-place (OGIP) was established from the data. This is in contrast to the p/z versus Gp material balance approach, which is seldom accurate early in the life of the field. This case history clearly illustrates the benefit of utilizing continuously measured pressure and rate data to obtain an accurate original gas-in-place early in a field's life. In addition, this paper demonstrates the benefit of permanently installed pressure gauges in subsea-completed satellite fields. Introduction Early accurate determination of OGIP is always desirable in a new gas field development, as this information is critical in decision-making for reservoir management. For example, the optimum number of wells or the need for compression at the surface depends on OGIP. In addition, the operator is often required to project production rates in order to secure a gas sales contract. These decisions are typically made early in the life of a field and erroneous estimates of OGIP can lead to poor decisions that may be costly or impossible to correct later in the field life. Various reserve estimation methods have been published in the literature ranging from basic material balance calculation to decline-curve analysis. Recently, Agarwal et al presented new production decline curves for analyzing well production data by combining type-curve and decline-curve analysis concepts. In this report, we applied Agarwal et al's analysis techniques to pressure and rate measurements over a period of approximately 3,000 days at Ballycotton. Subsequent analysis of short-term performance data showed that an accurate estimate of OGIP was established from the first six months of production. Same results were also confirmed independently using reservoir simulation while examining the effects of water influx and production interference from Kinsale Head. Background Information Geologic Setting and Field Description. The Ballycotton gas field lies approximately 25 miles off the coast of Cork, Ireland in the North Celtic Sea Basin. It was discovered in March 1989 and has been produced from well 48/20–2 since July 1991 as a satellite field via a single subsea well completion and tieback to the Kinsale Head's Bravo platform. A location map is shown in Fig. 1. The ‘A’ Sand producing interval in Ballycotton and Kinsale Head is the focus of this paper. This sand extends from Kinsale Head gas field in the south to Ballycotton gas field in the north, thus connecting the two fields by a common aquifer. Reference 3 gives a comprehensive geologic description of the region. The Kinsale Head gas field was discovered in 1971 and placed on production in October 1978. The existence of gas processing facilities at Kinsale Head made it commercially feasible to produce Ballycotton, which at the time of discovery, was thought to contain 80 BCF from a volumetric study. About 760 BCF of gas was produced from the ‘A’ Sand of Kinsale Head by the time Ballycotton was placed on-line. Geologic Setting and Field Description. The Ballycotton gas field lies approximately 25 miles off the coast of Cork, Ireland in the North Celtic Sea Basin. It was discovered in March 1989 and has been produced from well 48/20-2 since July 1991 as a satellite field via a single subsea well completion and tieback to the Kinsale Head's Bravo platform. A location map is shown in Fig. 1. The ‘A’ Sand producing interval in Ballycotton and Kinsale Head is the focus of this paper. This sand extends from Kinsale Head gas field in the south to Ballycotton gas field in the north, thus connecting the two fields by a common aquifer. Reference 3 gives a comprehensive geologic description of the region. The Kinsale Head gas field was discovered in 1971 and placed on production in October 1978. The existence of gas processing facilities at Kinsale Head made it commercially feasible to produce Ballycotton, which at the time of discovery, was thought to contain 80 BCF from a volumetric study. About 760 BCF of gas was produced from the ‘A’ Sand of Kinsale Head by the time Ballycotton was placed on-line.
aquifer, Ballycotton, cartesian analysis, decline-type curve match, derivative data, estimates of resource in place, field data, graph, interference, Ireland, Kinsale Head, liquid solution, Modeling & Simulation, OGIP, performance data, Petroleum Engineer, pressure decline, production control, production data, production monitoring, pseudoequivalent time, reserves evaluation, reservoir simulation, Reservoir Surveillance, resource in place estimate, spe 59791, Upstream Oil & Gas
Oilfield Places:
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (30 more...)
SPE Disciplines:
ABSTRACT This paper describes the results of a wave measurement experiment carried out at the Kinsale Head Gas field, off the South coast of Ireland between 21 and 23 November, 1984. Simultaneous wave recordings, of length up to two and a half hours, were made using wave buoy and wave staff devices. These recordings include the growth, peak and decay of a severe winter storm. A comparison is made between the wave parameters obtained from the two devices. This includes first order wave spectra and their derived height and period parameters as well as the most commonly used wave grouping parameters. The characteristic wave height and periods show good correlation between the wave buoy and staff while the chief grouping parameters demonstrate weaker dependence. The spectral peakedness parameter gave the strongest correlation but the mean run lengths were virtually un-correlated between the two locations. Each system gave similar values for the auto-correlation between successive wave heights with a weak but significant relationship. The Funke and Mansardshowed an even weaker dependency. This was slightly improved by employing a new modified factor. The agreement between SIWEH spectra was dependent on the length of the wave record. 1. INTRODUCTION With the development of compliant and floating oil production systems, wave groups are increasingly important to offshore engineers. Many authors have demonstrated the relationship between the slow drift motions of moored floating structures and the presence of wave modulation due to groups. Despite this relatively little is known about the occurrence of wave groups during storms. Attempts have been made to characterize nonrandom behavior of waves under two broad categories. Firstly, wave groups have been described in terms of the dependency of successive wave heights. The second category is the study of low frequency modulations of the sea surface. The former may be described as counting methods, wherein the wave heights are discretized and examined as a series of statistical events. The most common definition of a wave group is a run of consecutive waves whose heights exceed some threshold value. Figure 1 demonstrates this definition showing two wave, groups of length 3 and 4. Goda considers the mean run length of a record for threshold values of Hs ' the significant wave height, and Havg, the average wave height. Goda also demonstrated that the individual run containing the largest wave of the record is on average longer than other wave groups. This particular wave group is termed the "extreme wave group" (EWG) and has been proposed as a design criterion for capsize tests.
correlation, cross correlation, deviation, frequency, groupiness factor, hmax hs, Intercomparison, mean run length, Offshore Technology Conference, run length, siweh spectra, spectra, spectrum, subsea system, Upstream Oil & Gas, wave buoy, wave group, wave grouping parameter, wave height, wave train
Country:
- North America > United States > Texas (0.28)
- Europe > Ireland > Celtic Sea > County Cork > Celtic Sea (0.25)
Oilfield Places:
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 49/21 > Kinsale Field > Kinsale Head Field (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 49/16 > Kinsale Field > Kinsale Head Field (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 48/25 > Kinsale Field > Kinsale Head Field (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 48/20 > Kinsale Field > Kinsale Head Field (0.99)
ABSTRACT A detailed geotechnical investigation was undertaken at the Kinsale Head Gas Field in the Celtic Sea. Five-inch-diameter cores were recovered to a terminal penetration of 400 ft below the seafloor from two foundation borings drilled in a water depth of about 300 ft. Chalk extended continuously below 10-ft-thick surficial deposits of sand and gravel. Laboratory tests were conducted on the chalk samples to determine chemical and physical properties, and laboratory model techniques were developed to evaluate adhesion along a chalk-grout interface. The engineering properties of the chalk as determined from the field and laboratory study were used to develop suitable design parameters for two fixed offshore platforms recently installed in the Kinsale Head Gas Field. Graphical correlations of water content, unit dry weight, unconfined compressive strength and modulus of elasticity of the chalk are presented along with the chalk strength profiles with penetration. Chalk-grout adhesion results are discussed. The Celtic Sea chalk appears to be stronger and more dense than the English Upper Chalk and shows similarities to the chalk of Northern Ireland. Tests indicated that samples of fractured chalk softened and disintegrated rapidly when exposed to saltwater, unlike competent chalk which was unaffected by similar exposure. INTRODUCTION The constitution and properties of chalk from many regions of the British Isles are extensively documented. There is, however, an appreciable lack of information concerning chalk from the Celtic Sea area. In the fall of 1973, a detailed study was made to determine foundation conditions at two locations in the Kinsale Gas Field in the Celtic Sea (see Figure 1). The study was aimed at providing sufficient information for the design and installation of two template-type structures, requiring that two deep foundation borings (350 to 400-ft penetration) be made in the chalk. This paper presents the results of a comprehensive series of laboratory tests made to determine the geotechnical properties of chalk samples recovered from the borings. Two 8-pile platforms were recently installed successfully at the study locations. The foundation system consisted of large-diameter pipe piles driven to about 50-ft penetration with smaller-diameter pipe piles grouted into predrilled holes in the chalk below 50-ft penetration. Information concerning foundation design parameters and installation details of these piles will hopefully be published in the near future. CHALK CORING OPERATIONS The Kinsale Head Gas Field is located approximately 35 miles southeast of Cork, Ireland, as shown in Figure 1. In the area of the gas field, water depths range from 283 to 310 ft. The measured water depth at the boring locations was 295 ft, subject to tidal variations of about 13.5 ft. The seafloor is generally level, except for isolated areas of small sand waves. Shallow seismic information indicated that there were areas where unconsolidated sediments were present at the seafloor and areas where chalk outcropped at the seafloor. At the boring locations, these sediments were approximately 10 ft thick, consisting mainly of coarse sand and gravel. Beneath the surficial deposits, chalk exists continuously to below the terminal penetration of the borings.
adhesion, celtic sea chalk, chalk, chalk specimen, chalk-grout adhesion, chalk-grout interface, drilling fluids and materials, drilling operation, grout, interface, northern ireland, penetration, Reservoir Characterization, saltwater, specimen, strength, test specimen, unconfined compressive strength, unit dry weight, Upstream Oil & Gas, water content
Country:
- Europe > Ireland > Celtic Sea > County Cork > Celtic Sea (0.94)
- Europe > United Kingdom (0.90)
Oilfield Places:
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 49/21 > Kinsale Field > Kinsale Head Field (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 49/16 > Kinsale Field > Kinsale Head Field (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 48/25 > Kinsale Field > Kinsale Head Field (0.99)
- Europe > Ireland > Celtic Sea > North Celtic Sea Basin > Block 48/20 > Kinsale Field > Kinsale Head Field (0.99)
SPE Disciplines:
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