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Collaborating Authors
Gyda Field
Since 2011, the Oil and Gas Corporation of Newfoundland and Labrador (Oilco, formerly Nalcor Energy Oil and Gas) along with partners Petroleum Geo-Services (PGS) and TGS Geophysical have embarked on a multiyear regional two-dimensional (2D) seismic program offshore Newfoundland and Labrador (NL). More than 180,000 line kilometers of 2D broadband seismic have been acquired by 2022 as well as nine three-dimensional (3D) surveys covering over 60,000 square kilometers of frontier basins. The seismic data collected have led to some major scientific advancements of the regional geology, such as the newly defined Chidley, Holton, Henley, and Hawke sedimentary basins off the Labrador coast (Carter et al., 2013), and a Lower Tertiary play trend (Wright et al., 2016), which was imaged on the 2015 multiclient 3D seismic survey. The NL offshore now has 20 defined sedimentary basins ranging from the Paleozoic to Cenozoic ages, all of which are potential candidates for oil and gas exploration (Figure 1). As part of Oilco's exploration strategy, an ice and metocean study was considered a critical piece of information in an area of frontier exploration. Oilco issued the Metocean Climate Study Reports (and associated Nalcor Exploration Strategy System (NESS) database and Geographic Information System (GIS)) for Phase 1 in May 2015 (C-CORE, 2015; King et al., 2015), Phase 2 in September 2017 (C-CORE, 2017), and Phase 3 in April 2022 (C-CORE, 2022). Phase 1 covered the area from 45.5
- North America > Canada > Newfoundland and Labrador > Labrador (1.00)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean (0.47)
- North America > Canada > Newfoundland and Labrador > Newfoundland > St. John's (0.29)
- North America > United States > Alaska > North Slope Basin > Burger Field > Kuparuk Formation (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Orphan Basin (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin (0.99)
- (14 more...)
Abstract An operator on the Norwegian Continental Shelf oversaw the execution of a plug and abandonment (P&A) campaign comprising 32 wells in a mature field. The barrier evaluation plan was developed based on previous experiences in a field with similar properties and conducted by another operator that included the cement and solids evaluation using conventional ultrasonic technology. This paper describes how the introduction of the latest generation transducers aided in shortening the P&A campaign duration, saving days of rig time. The entire logging plan for barrier evaluation within the32 well P&A campaign was custom developed, executed, and jointly analyzed by the operator and the service company. The logging intervals, well fluid and multiple casing size targets were considered during the strategic selection process. This enabled convergence to a solution that provided a comprehensive evaluation while avoiding multiple logging descents and achieving a faster acquisition speed without degradation of the results. Acquisition capabilities have been constantly evolving over the past decades. The full data acquisition campaign described in this paper was improved from the original plan and adjusted to include a combination of ultrasonic pulse-echo and pitch-catch imaging measurements, third interface echo (TIE), an output of the pitch-catch method supported by and the traditional sonic technology response, enabling quick annular material identification as well as casing cut-and-pull decision making. The combination of all measurements allowed a robust solution that is independent from wellbore logging fluid and potentially unknown annular materials that segregates or changes through the life of these wells. The technology blend adopted in this field enabled a direct logging time reduction of 50% and allowed the acquisition of multiple nonconcentric casing sizes in a single descent, which is not possible with previous generation technologies. The overall result helped the operator to reduce their greenhouse gas (GHG) emissions during those operations by shortening the barrier evaluation campaign length by 10 rig days. The operator was able to significantly reduce the rig time spent in the campaign the implementation of the latest ultrasonic barrier evaluation logging technology, thus reducing their overall GHG emissions without compromising the results of the original objectives.
- Europe > United Kingdom > North Sea > Central North Sea > Forties Formation (0.99)
- Europe > Norway > North Sea > Cromer Knoll Group > ร sgard Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Sleipner Formation (0.99)
- (6 more...)
Lithium Extraction From North Sea Oilfield Brines Using Ion Exchange Membranes
Disu, Botelho (School of Engineering, University of Aberdeen, Aberdeen, UK) | Rafati, Roozbeh (School of Engineering, University of Aberdeen, Aberdeen, UK) | Haddad, Amin Sharifi (School of Engineering, University of Aberdeen, Aberdeen, UK) | Fierus, Nabihah (School of Engineering, University of Aberdeen, Aberdeen, UK)
Abstract The annual demand for lithium for low-carbon technologies applications has been trading exponentially forward, 965% more in 2050 than the quantity demanded in 2017. In the current chain of demand, there is a necessity for continuous lithium production from both conventional sources (i.e., salt lakes and rock minerals) as well as the incorporation of novel extraction sites from alternative brine resources such as Oilfield and Geothermal. In the present paper, the lithium potentiality of the North Sea is evaluated with fields in the Central-East and Southern-West reaching the highest regional concentration of 40 ppm. Those include oilfields such as Montrose, Arbroath, Ula, Nelson, Brisling, Gyda, Ekofisk and Bream, as well as gas fields such as the Esmond, Anglia, Lemman, Ann, and Viking, with the possibility of brine enrichment extending itself even to shallow waters fields around the Groningen region. To experimentally evaluate the potential extractability of lithium from those oilfield brine resources in the North Sea, ion-sieve adsorbents (Li1.6Mn1.6O4) were prepared from commercially available LiMnO2 and formed into three different ion-exchange membranes. The foam had the best performance out of those structures, displaying a higher and much stabler powder insertion capacity compared to granular and flat sheet membranes, which registered significant material loss. At an optimum polymeric concentration of 10% and MNO/PVA ratio of about 50%, the foam membrane had the highest theoretical extraction capacity of 9.94 mg/g, followed by granular and flat sheet, with 7.36 and 7.24 mg/g, respectively. Those membranes had good selectivity forward lithium ion in the presence of other competing cations when used on synthetic oilfield brine with concentration mimicking that of Buchan field, being able to efficiently recover 18.4% (foam), 17% (granular), and 14.37% (flat sheet) of lithium. However, the recovery capacity was increased up to 50% when non-formed HMO powder was used, with selectivity in the following decreased order of affinity, Li > Mg > Na > Ca2 > K. The powder recoverability raises the lithium production prospect from North Sea brine to about 26.2 kg per day with an estimated market value of 1834 USD for the produced quantity.
- North America > United States > Texas > Permian Basin > Fields Field (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 48/6 > Hyde Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Witch Ground Graben > P 2170 > Block 21/1a > Greater Buchan Field (0.99)
- (75 more...)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Well fluid analysis (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (0.94)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Zechstein Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Ula Formation (0.99)
- Europe > United Kingdom > North Sea (0.89)
- (3 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- (4 more...)
Perf, Wash and Cementing Technique Remediates Cemented Annulus to Achieve High Quality Bond Across the Entire Interval in Complex Slot Recovery Operation
Torvestad, Bjรธrn Tore (Archer) | Stokkeland, Thore Andre (Archer) | Fliss, Andreas (Archer) | Zapata Bermudez, Fernando (Archer) | Fagna, Jan Ove (Archer) | Fossdal, Tormod (Equinor) | Carlsen Stanghelle, Marie (Equinor)
Abstract The objective of this abstract is to demonstrate how a complex slot recovery operation was performed to permanently plug the main reservoir and the intermediate formation to facilitate a new sidetrack. There were several challenges to overcome in this well and it was favorable to install the annular barriers as deep as possible just above a 7" tieback packer. The 9 5/8" casing was logged and the annulus condition at the depth was cemented, however most of the interval had patchy cement bond with medium isolating potential. Some of the interval had well bonded heterogeneous cement around the annulus, but not enough continues bond to comply with company standards and regulatory requirements in the country. Based on this challenge, a procedure using the perf, wash, and cementing technique, all in a single trip, was chosen as the best solution as this technique had been very successful in achieving high quality annular barriers across this field for years. High cement content in the annulus was risk assessed and planned accordingly. The decision was made to perforate two different intervals using TCP guns to subsequently drop them in the rat hole. The casing was perforated from 2155 โ 2130 mMD and 2111 โ 2069 mMD with the overall goal of achieving 86 meters of continues high-quality cement. The next step was to wash the perforated intervals, and that was done effectively with declining standpipe pressure and a unique system that focus the washing fluids into the perforations using inversed swap cups to result in a large amount of cement coming over the shakers. The large amount of cement over the shakers was a testament of the efficiency of the system. It clearly shows the capabilities of restoring barriers by removing patchy cement and provide a new high quality cement plug across the interval. The operation was completed with a flawless cement job utilizing the uniquely engineered Pump and Pull method that is specific to this system and part of the standard operating procedure of the provider. The results speak for itself; the entire operation was a milestone for both the service company and the operator. After the cement set up it was drilled out and the annulus was re-logged to verify the effectiveness of the operation. The result was high quality cement bond across both the perforated intervals and the customer had achieved 86 meters of high-quality cement bond in the annulus. The objective was met, and the complex dual interval operation was successfully executed with industry leading performance. The operation has proved its efficiency in a cemented annulus setting a new benchmark for the system going forward.
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lista Formation (0.99)
- (4 more...)
Summary This study aims to demonstrate the changes to scale inhibitor squeeze lifetimes in a polymer flooded reservoir vs. a waterflooded reservoir. A squeeze campaign was designed for the base waterflood system, then injection was switched to polymer flooding (PF) at early and late field life. The squeeze design strategy was adapted to maintain full scale protection under the new system. During the field life, the production of water is a constant challenge. Both in terms of water handling, but also the associated risk of mineral scale deposition. Squeeze treatment is a common technique, where a scale inhibitor is injected to prevent the formation of scale. The squeeze lifetime is dictated by the adsorption/desorption properties of the inhibitor chemical, along with the water rate at the production well. The impact on the adsorption properties and changes to water rate on squeeze lifetime during PF are studied using reservoir simulation. A 2D 5-spot model was used in this study, which is considered a reasonable representation of a field reservoir under waterflooding (WF)/PF. It was observed that when applying polymer (HPAM) flooding, with either a constant viscosity or with polymer degradation. The study concludes that the number of squeeze treatments was significantly reduced as compared to the waterflood case. This is due to the significant delay in water production induced by the polymer flood. When the polymer flood was initiated later in field life, after 0.5 PV (reservoir PVs) water injection, resulting in 70% water cut approximately, the number of squeeze treatments required was still lower than the waterflood base case. However, it was also observed that in all cases, at later stages of field life the positive impact of PF on squeeze lifetime begin to diminish, due in part to the polymer breakthrough, which results in higher water viscosity in the production near-wellbore region. Preventing the overflush to be as effective transporting the scale inhibitor. This study represents the first coupled reservoir simulation/squeeze treatment design for a polymer flooded reservoir. It has been demonstrated that in over the course of a field lifetime, PF will in fact reduce the number of squeeze treatments required even with a potential reduction in inhibitor adsorption. This highlights an opportunity for further optimization and a key benefit of PF in terms of scale management, aside from the EOR.
- Asia > Middle East (0.69)
- Europe > United Kingdom (0.68)
- North America > United States > Texas (0.28)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Zechstein Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Ula Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Differentiation of Cement & Creeping Formation Behind Casing Key to Successful Plug and Abandonment
Gupta, Shilpi (Schlumberger) | Vindheim, Helge (Repsol Norge AS) | Govil, Amit (Schlumberger) | Obando, Guillermo (Schlumberger) | Kumar, Apoorva (Schlumberger) | Agrawal, Gaurav (Schlumberger) | Dutta, Shaktim (Schlumberger)
Abstract The Gyda field in the North Sea operated by Repsol was proven in 1980 and the platform started producing in 1990. In June 2017, the Norwegian authorities approved the decommissioning plan for the Gyda field. The decommissioning scope included the permanent plugging of 32 wells in the field. Decommissioning is estimated to cost several hundred million dollars and is expected to finish in 2022. As per the NORSOK standards, each well needs to have confirmed barriers to isolate inflow zones, both for preventing from flowing to the surface and hindering crossflow between them. Cement and creeping formation are both considered to be potentially effective barrier elements. However, the criteria and verification methods used to confirm formation creep and cement as barrier elements are different and hence require an innovative interpretation technique which is presented in this paper. As per the regulations and standards, it is critical not only to evaluate the quality of the circumferential bond for cement and formation creep but also to determine their respective bond length. The most important measurement to accurately determine those criteria in each well is through the ultrasonic and flexural attenuation tool. However, interpretation to differentiate formation creep from cement presents challenges, especially when they have similar ultrasonic properties. Quite often, they coexist at the same depths on different sides behind the casing. Barrier evaluation becomes even more challenging with added complexities such as borehole mud settling due to high deviation, high eccentricity, casing damage, or presence of a microannulus. This paper discusses the techniques and interpretation methods used to accurately evaluate barrier elements, differentiate between cement and formation creep, estimate the tops of cemented areas, and eliminate complex challenges posed by mud, deviation, eccentricity, and wet microannulus sections. Successful and accurate determination of the potential presence and location of annulus barrier elements has been fundamentally important for Repsol to meet the regulatory requirements. A special interpretation technique was established using integrated data evaluation to differentiate creeping formation from cement. This technique successfully determined accurate barrier intervals, helping to meet all the regulatory requirements. The processes and methods have been audited and evaluated by the Petroleum Safety Authority Norway.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > Norway Government (0.54)
- Europe > Norway > North Sea > Cromer Knoll Group > ร sgard Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Skagerrak Formation (0.99)
- (8 more...)
The Oda Field: From Scale Prediction to Reality - Why Squeezing was Not Necessary Despite a High Calcium Sulphate Risk
Kaasa, Baard (Scale Consult) | Somme, Bodil (Spirit Energy) | MacDonald, Ross (Spirit Energy) | Kjรธrsvik, Kristin (Spirit Energy) | Saunes, Anders (Spirit Energy) | Heath, Stephen (Creative Chemical Solutions Ltd) | Stamnes, Marius (Scale Protection)
Abstract In this paper we will tell the story of a sub-sea well in the Oda field where the predicted downhole calcium sulphate (CaSO4) scale risk did not concur with observations in the field. Seawater was injected into the oil leg and the first sample collected at 5% water cut had ~ 80% seawater breakthrough, with a harsh CaSO4 scaling tendency predicted (SR 3.5 at 120ยฐC). A squeeze treatment was planned as part of the mitigation strategy and, in addition, continuous downhole injection of scale inhibitor (SI) was instigated to provide protection to the production tubing, flow line and topside facilities. An extensive monitoring program consisting of productivity monitoring, weekly produced water ionic composition and ESEM/EDX bulk scale analysis (BSA) was instigated to confirm the scaling risk. The water cut increased as did the seawater content to ~90%, however, the results of the BSA did not indicate any significant amounts of CaSO4 scale on the filters indicating stable produced water. Scale and 1D reservoir simulations also showed that to match the produced water composition with the correct FW:SW ratio, CaSO4 should have precipitated in the reservoir, but not to equilibrium resulting in a produced water with SR higher than one. In addition, a further increase in seawater content would lead to lower scale risk and the produced water was confirmed as stable even with a calculated SR of about 3-3.5. Several scale prediction models were evaluated with the same outcome. A new scaling risk matrix created from the BSA field data, backed up by the trends in measured vs predicted ion data, indicated no significant scale risk to the Oda well which is in contrast to what was predicted. Based upon this data it was agreed that the planned squeeze treatment was no longer required, but this still raised the question of why the well didn't scale. Several theories including metastability, natural inhibition and kinetic effects coupled with partial protection by downhole injection of SI will be discussed. In addition, this paper will highlight the benefits of using a holistic, integrated scale management strategy, consisting of scale and reservoir simulations combined with field data (ions and BSA), to identify a more realistic field risk and save unnecessary treatment costs.
- North America > United States (1.00)
- Europe > Norway > North Sea > Central North Sea (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.36)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 405 > Block 8/10 > Oda Field > Zechstein Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 405 > Block 8/10 > Oda Field > Ula Formation (0.99)
- (16 more...)
Abstract Natural geochemical data, which refer to the natural ion concentration in produced water, contain important reservoir information, but is seldomly exploited. Some ions were used as conservative tracers to obtain better knowledge of reservoir. However, using only conservative ions can limit the application of geochemical data as most ions are nonconservative and can either interact with formation rock or react with other ions. Besides, mistakenly using nonconservative ion as being conservative may cause unexpected results. In order to further explore the nonconservative natural geochemical information, the interaction between ion and rock matrix is integrated into the reservoir simulator to describe the nonconservative ion transport in porous media. Boron, which is a promising nonconservative ion, is used to demonstrate the application of nonconservative ion. Based on the new model, the boron concentration data together with water production rate and oil production rate are assimilated through ensemble smoother multiple data assimilation (ES-MDA) algorithm to improve the reservoir model. Results indicate that including nonconservative ion data in the history matching process not only yield additional improvement in permeability field, but also can predict the distribution of clay content, which can promote the accuracy of using boron data to determine injection water breakthrough percentage. However, mistakenly regarding nonconservative ion being conservative in the history matching workflow can deteriorate the accuracy of reservoir model.
- Europe > Norway > North Sea (0.46)
- Asia (0.46)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.75)
- South America > Ecuador > Oriente Basin (0.99)
- North America > United States > Texas > Frio Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 190 > Brent Group > Tarbert Formation (0.99)
- (9 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Abstract This study aims to demonstrate the changes to scale inhibitor squeeze lifetimes in a polymer flooded reservoir versus a water flooded reservoir. A squeeze campaign was designed for the base water flood system, then injection was switched to polymer flooding at early and late field life. The squeeze design strategy was adapted to maintain full scale protection under the new system. During the field life, the production of water is a constant challenge. Both in terms of water handling, but also the associated risk of mineral scale deposition. Squeeze treatment is a common technique, where a scale inhibitor is injected to prevent the formation of scale. The squeeze lifetime is dictated by the adsorption/desorption properties of the inhibitor chemical, along with the water rate at the production well. The impact on the adsorption properties and changes to water rate on squeeze lifetime during polymer flooding are studied using reservoir simulation. A two-dimensional 5-spot model was used in this study, considered a reasonable representation of a field scenario, where it was observed that when applying polymer (HPAM) flooding, with either a constant viscosity or with polymer degradation, the number of squeeze treatments was significantly reduced as compared to the water flood case. This is due to the significant delay in water production induced by the polymer flood. When the polymer flood was initiated later in field life, 0.5PV (reservoir pore volumes) of water injection, water cut approximately 70%, the number of squeeze treatments required was still lower than the water flood base case. However, it was also observed that in all cases, at later stages of field life the positive impacts of polymer flooding on squeeze lifetime begin to diminish, due in part to the high viscosity fluid now present in the production near-wellbore region. This study represents the first coupled reservoir simulation/squeeze treatment design for a polymer flooded reservoir. It has been demonstrated that in over the course of a field lifetime, polymer flooding will in fact reduce the number of squeeze treatments required even with a potential reduction in inhibitor adsorption. This highlights an opportunity for further optimization and a key benefit of polymer flooding in terms of scale management, aside from the enhanced oil recovery.
- North America > United States (1.00)
- Asia > Middle East (0.69)
- Europe > United Kingdom (0.68)
- Research Report > New Finding (0.48)
- Overview (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.83)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Zechstein Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Ula Formation (0.99)