This paper is based on the analysis of the ultrasonic/sonic data of the 9 5/8-in. casing logging of the 14 wells of the Varg field within the Norwegian Continental Shelf. While writing this papper Varg field was undergoing a plug and abandonment (P&A) phase after 19 years of production. High-quality bonding is observed behind the 9 5/8-in. casing far above expected theoretical top of cement within single casing areas. This bonding is attributed to the formation influence. Formation is used as an alternative to traditional cement barriers during P&A, and its use is regulated by the legislation.
The paper aims to develop better understanding of the mechanisms responsible for formation bonding development. The percentage of observed bonding at "high" and "high and moderate-to-high" quality is calculated within each well and is related to the various factors that could influence formation bonding development. Factors such as duration of time lapsed from well completion to well logging, type of well (producer versus injector), geological formation, type of drilling mud used, duration of production periods, volumes of production, and well deviation and azimuth were looked at to determine observable trends and relationships.
The results of the study allowed us to conclude which factors are critical or influence formation bonding. Based on the observations, recommendations can be made for the selection of the first well to be logged on the planned P&A campaigns. Correct selection of the first well saves time and resources on the formation testing for the qualification of the formation as a barrier.
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.
Mohd Hatta, Siti Aishah (PETRONAS Carigali Sdn Bhd) | Zawawi, Irzee (PETRONAS Carigali Sdn Bhd) | Gupta, Anish (PETRONAS Carigali Sdn Bhd) | Ahmad Nadzri, M. Safwan (PETRONAS Carigali Sdn Bhd) | Salleh, Nurfarah Izwana (PETRONAS Carigali Sdn Bhd) | Jeffry, Suzanna Juyanty M. (PETRONAS Carigali Sdn Bhd) | Sharif, Natasha Md (PETRONAS Carigali Sdn Bhd) | Ishak, Izza Hashimah (PETRONAS Carigali Sdn Bhd) | Maoinser, M. Azuwan (Universiti Teknologi PETRONAS)
Field B is a marginal green field located offshore Sarawak, Malaysia with formation depth of less than 1000 meters. The compressional sonic transit time range is from 100 – 115 μs/ft, which immediately triggered the possibility of using active downhole sand control as this range is assumed to be unconsolidated. However, the rock mechanical strength characterization tests from sidewall core indicated contradictory result of a consolidated formation. Since the field is considered as a small field, the cost of the well especially on downhole sand control device need to be extensively optimized. Hence, sand prediction study for a small green field development using field and laboratory measurements was performed.
Several methodologies of sand prediction were utilized to evaluate the optimum sandface completion and sand control management for the field. Empirical and analytical sand prediction based on the well logs, sidewall cores analysis, and sand prediction software are employed to evaluate the likelihood of sand production and the optimum well completion design for the field development. The available data from appraisal wells of Field B is also calibrated to the nearby brown field, Field A that has been producing for more than 30 years.
This paper will discuss on the sand onset prediction results between full perforation versus oriented perforation, and pressure depletion impact on the sand production. The study shows that the formation is not prone to sand production especially in the early part of the production life with high reservoir pressure and low watercut. The expected Critical Drawdown Pressure (CDP) generated from different methods show large variation of sand onset pressure if the sandface is completed using full perforation. Oriented perforation tremendously expands the sand free drawdown limit. Based on the results of the study, expected reservoir pressure depletion and watercut, the completion of the wells adopted Oriented Perforation with no other downhole sand control equipment.
This paper is beneficial for petroleum and well completion engineers especially on sand prediction part of well completion design in development stage. This will assist in ensuring the field meets the EUR and bring forward economic value as well as well integrity assurance.
Recent field applications and laboratory studies have recognized that low-salinity waterflooding (LSW) is a potentially effective technique to achieve sufficient recovery in sandstone reservoirs. Researchers have noted that the impacts of clay content, rock permeability, and pore-throat radius are still unclear on the performance of LSW. This paper reports the results of coreflood, zeta-potential, X-ray-powder-diffraction (XRD), X-ray-fluorescence (XRF), scanning-electron-microscope (SEM), nuclear-magnetic resonance (NMR), and high-pressure-mercury-injection experimental investigations on these parameters.
The main objectives of this work are to examine the performance of LSW by use of four sandstone rocks during secondary- and tertiary-recovery modes; to investigate the role of clay content, rock permeability, and average pore-throat radius on the performance of LSW; and to evaluate the effects of mineral type, brine salinity, cation type, and pH on the zeta-potential measurements. Zeta-potential measurements were conducted for rock/brine interfaces to determine the suitable injection brine for the used sandstone rocks. Various brines were used, including seawater (SW), 20% diluted SW, 0.5 wt% NaCl, 0.5 wt% MgCl2, and 0.5 wt% CaCl2. Then, a set of comprehensive coreflood tests were conducted with Bandera, Parker, Gray Berea, and Buff Berea outcrop sandstone cores. The coreflood experiments were conducted with 6- and 20-in.-length and 1.5-in.-diameter outcrop cores at 185°F. Oil recovery, pressure drop, and pH were observed and analyzed after each coreflood experiment.
On the basis of the results attained, the Parker, Bandera, Gray Berea, and Buff Berea sandstone cores showed additional oil recoveries of 4.3, 9.2, 13.3, and 17.1% of original oil in place (OOIP), respectively, through the injection of low-salinity brine (5,000 ppm NaCl) as the secondary recovery mode. The average pore-throat radius (rock quality) has a higher effect in the performance of LSW than in high-salinity waterflooding (HSW) on the secondary recovery mode. The incremental oil recovery (microscopic) for the LSW increased from 4.3 to 17% when the average pore-throat radius (R35) of the core increased from 1.4 to 8.5 μm.
The total clay content and the clay composition are not the main factors that influence the LSW performance. The distribution of the clays seems to be playing a significant role. The measured zeta potentials of kaolinite and montmorillonite particles in 5,000 ppm NaCl brine at 77°F and pH 7 were 26.5 and 29.4 mV, respectively. The zeta-potential values indicated a stronger negative charge on muscovite and albite minerals of 33.8 and 31.5 mV, respectively. Zeta-potential values indicated a less-negative charge on the chlorite and illite particles than the other minerals. It seems that chlorite and illite contribute to a smaller electrical-double-layer expansion than those of kaolinite, feldspars, montmorillonite, and muscovite. On the other hand, the zeta-potential values of calcite and dolomite particles are 1.0 and 4.5 mV, respectively. The presence of dolomite and calcite would decrease the effect of the low-salinity brine to improve oil recovery.
Steel wire ropes use individual wires moving relative to each other in a spherical structure. The behaviour of wire ropes exposed to loading, are not as beams or other structural elements. The ropes function is optimal when the individual wires can move in the rope. Several internal and external conditions can prevent the individual wires to move optimal, and change the behaviour of the rope. Based on two double overload failures, the paper describe the condition and behaviour of the failed steel wire ropes mainly as consequences of distorting the behaviour of the individual wires.
Offshore steel wire ropes are made of steel with typically 0.75-0.86% carbon content. The wires are galvanized using zinc. The individual wires are lubricated to fill the spaces between the individual wires. They are helically wound together to form a steel wire rope in specified combinations. If specified by the customer, they add polymer coatings outside the rope. They make end terminations, and the steel wire ropes are tested. The ultimate strength of offshore steel wires is typically about 2000MPa.
We have previously summarized the failures of Norwegian offshore anchoring lines, including the failures of steel wire ropes (Kvitrud, 2014). We have included information about Norwegian steel wire rope failures in lifting and drilling appliances. We are relying heavily on the industry investigative reports. Information about failures in offshore steel wire ropes are in e.g. Ma et al (2013), Leeuwenburgh and Brinkhuis (2014) and Leeuwenburgh (2015).
We describe the circumstances of the two Norwegian double mooring line failures. Then we describe the change of behaviour caused by violation of the individual steel wires possibility to move relatively to each other, as a function of lubrication, wear, corrosion, the distribution of loads over the cross-section of the rope, twist, bending, payout of lines and testing to 100-year load levels. We concentrate on the rope behaviour, and do not discuss the size of the tension. The size of the loads from the waves are currently investigated in the EXWAVE JIP project.
Recent field applications and laboratory studies have recognized that low-salinity waterflooding as a potentially effective technique to achieve sufficient recovery in sandstone reservoirs. It was found that the impact of clay content, rock permeability, and rock quality are still questionable on the performance of low-salinity waterflooding.
A set of comprehensive coreflood tests have been conducted to estimate displacement efficiency and investigate the effect of clay content and rock quality using Bandera, Parker, Grey Berea, and Buff Berea sandstone cores. The coreflood experiments have been conducted on 20 and 6 in. length and 1.5 in. diameter outcrop cores at 185°F and 500 psi. Oil recovery, pressure drop, and pH were observed and analyzed after each coreflooding experiment. The mineralogy of the samples was assessed by X-ray powder diffraction, scanning electron microscopy, and X-ray fluorescence.
The oil recovery from conventional waterflooding ranged from 24.6 to 44.7% OOIP. The oil recovery decreased when the reservoir permeability decreased. The Bandera, Parker, Grey Berea, and Buff Berea sandstone cores showed additional oil recovery ranging from 4 to 17% OOIP through injection of low-salinity brine (5000 ppm NaCl) as a secondary recovery mode. As the permeability increased from 6 to 167 md, an additional oil recovery up to 32.9% of OOIP was observed by low-salinity waterflooding. None of the three sandstone rock types (Buff Berea, Grey Berea, and Parker) showed a response in the tertiary recovery mode. A significant incremental oil recovery of 6.9% OOIP was recovered in the tertiary mode for the Bandera sandstone rock. No direct relation was found between the total clay contents and oil recovery. In addition to the clay content, the sandstone rock quality and minerals distribution appears to play a key role in the effectiveness of low-salinity waterflooding. The rock quality has a significant effect in the performance of low-salinity waterflooding. The incremental oil recovery increased from 4 to 17% when the average pore-throat radius (R35) of the core increased from 1.3 to 8.7 microns.
Waterflooding is the most common type of supplementary recovery in which water is injected into the reservoir and displaces oil towards the producing zone. In the conventional waterflooding, the used injection water may be taken from the nearest available source. These sources include produced water, rivers, lakes, seawater, and aquifers. Historically, the physical mechanism behind this improvement in oil recovery was attributed to the pressure maintenance and displacement of oil by injected water. Based on the conventional view, the injection brine composition and salinity were believed to have no effect on the efficiency of oil recovery by waterflooding (Schumacher 1978). Hughes and Pfister (1947) pointed out that brines would keep the clay content of producing sands in a permanently flocculated condition, and therefore, brines were recommended for use in the secondary recovery mode by waterflooding.
Over the last decade several laboratory studies and field tests have shown that low-salinity waterflooding (LSW) and smart waterflooding improved oil recovery compared to high-salinity waterflooding (HSW) for sandstone and carbonate reservoirs. LSW flooding involves injecting brine with a lower salt content or ionic strength. Previous laboratory and field tests indicated that the injected brine was in the range of 500–5,000 parts per million (ppm) of total dissolved solids (TDS) (Yildiz and Morrow 1996; Nasralla and Nasr-El-Din 2011). Yildiz and Morrow (1996) showed that changes in injection-brine composition can improve recovery, thereby introducing the idea that the composition of brine could be varied to optimize waterflood recovery. Tang and Morrow (1997) noticed that LSW has a good potential to improve oil recovery. Tang and Morrow (1999) concluded that the presence of clays, initial water saturation, and crude oil were all necessary for LSW to increase oil recovery.
Extensive experimental work has indicated that Low-Salinity Waterflooding (LSW) is an enhanced oil recovery technique that improves oil recovery by lowering and optimizing the salinity of that injected water. Most of the LSW studies focused on the injection of brine salinity and composition. The question remains how does the salinity and composition of reservoir connate water affects the LSW performance. Therefore, in this paper different connate water compositions were used (TDS varies from 1550 up to 174156 ppm) to investigate the role of reservoir connate water on the performance of LSW.
Nine Spontaneous Imbibition (SI) experiments and six coreflood experiments were performed. Two sandstone types (Bandera and Buff Berea) with different clays contents and stock-tank crude oil samples were used in all the experiments. This work describes experimental studies of SI of oil by low-salinity and high salinity brines using 20” long outcrop sandstone samples. This study focused on the effect of connate water composition and temperature, 77 and 160°F, on the performance of LSW. The coreflood experiments have been conducted using 6 in. outcrop Buff Berea sandstone cores at 150°F and 500 psi. Oil recovery and pressure drop were observed and analyzed after each coreflooding experiment to examine the effect of the connate water composition (Na+, Ca+2, and Mg+2) on the performance of the LSW in secondary recovery mode.
Reservoir connate water composition and salinity have a dominant influence on the oil recovery rate. The Ca2+, Mg2+, and Na+ ions play a key role in oil mobilization in different sandstone rocks. Reservoir cores saturated with connate water contained divalent cations of Ca+2 and Mg+2 showed higher oil recovery for cores saturated with monovalent cations Na+. Low-salinity waterflooding showed a high potential to improve oil recovery in the SI experiments at different temperature levels. For high permeability Buff Berea cores, the SI oil recovery ranged from 38 to 69% OOIP, while oil recovery of the low permeability Bandera cores ranged from 17 to 45% OOIP at 77°F and 14.7 psia. As the temperature increased from 77 to 160°F, an additional oil recovery up to 4.2% of OOIP was observed by SI for Buff Berea cores. From the coreflood experiments, low-salinity brine had a significant positive effect on oil recovery for sandstone cores saturated with divalent cations (Ca+2 and Mg+2). The magnitude of incremental oil recovery increased from 51.9 to 58.9% OOIP when the reservoir connate water salinity increased from 3,420 to 36,350 ppm. On the other hand, increasing the monovalent cations (Na+) from 1,550 to 137,670 ppm resulted in slight increase in oil recovery (1.2% OOIP). The oil recovery from the coreflood runs for the Buff Berea cores ranged from 58.9 to 35.9% OOIP. The oil recovery decreased when the salinity of reservoir connate water decreased.
Water injection at the edge of oilfields is a common method for enhancing overall oil recovery. This has several beneficial effects include: the pressure differential between the field and the production well is maintained; the elevated pressure prevents the field from developing a discrete gas phase; and oil is ‘‘swept’’ in front of the injected water (Archer and Wall 1986). Water in oilfields can have a number of sources including connate water, seawater, aquifer, and even juvenile (magmatic) water. In the past, it was believed that the composition of the injection brine had no effect on the efficiency of oil recovery by waterflooding. Recent laboratory and field observations have indicated the possibility of reducing the residual oil saturation when the injection of conventional water (seawater and/or formation water) is replaced with the injection of low-salinity brines.
Low salinity waterflooding (LSWF), versus high salinity waterflooding (HSWF) has been the focus of significant research at various centres around the world, yet there is still considerable debate over the exact mechanism that provides incremental oil recovery. The use of the LSWF technique is not widespread in the United Kingdom continental shelf (UKCS). However, it has been announced that the Clair Ridge development will deploy low salinity waterflooding (LSWF) in secondary mode from the start of field life, and a number of companies are currently assessing the applicability of the technique through high level screening and core flooding. Forecasting the potential oil recovery under LSWF is heavily influenced by the simulation technique that is used. Presently the most widely discussed approach is the use of a weighting table with relative permeabilities representing the high and low salinity cases. As the grid block falls below threshold salinity, the simulator utilises the weighting table to assign an interpolated value of salinity. This value of salinity is utilised to represent a change in wettability. While this approach approximates the net effect of LSWF, it does not capture the oil/ rock/ brine interaction. This study examines the modelling approach to LSWF utilising an in-house generic Forties Palaeocene model in CMG’s STARS simulator. The conventional approach of modelling LSWF using high and low salinity relative permeabilities is compared to the latest Multi-component Ion Exchange (MIE) methods by numerical simulation to assess the impact on incremental oil recovery. A sensitivity analysis is then carried out on the effects of specific parameters on incremental oil recovery, utilising published data from fields in the Forties Palaeocene fan system. A discussion is provided. The impact on secondary recovery was accessed with respect to wettability alteration; injection salinity ( LSWF versus HSWF ); oil viscosity and aquifer influx. The application of LSWF in secondary mode to the Forties Palaeocene Sandstones was found to be favourable for the case of mixed-wet reservoirs.
Low salinity waterflooding (LSWF) is an enhanced oil recovery (EOR) technique which is of growing interest,as it represents a low cost and flexible form of EOR. The technique involves the injection of water at of a significantly lower salinity, compared to the natural salinity of the reservoir connate water. Until recently, although it was known that the ionic composition of a fluid flowing in a porous medium does influence the measured permeability ( Schleidegger 1974), the manipulation of this effect to improve oil recovery by injecting water of a different salinity and ionic composition to that of the natural formation water, had not been considered. As compared to the normal method of injecting seawater ( HSWF), LSWF is seen as a viable EOR technique. Further, LSWF offers the potential to increase recoverable oil without the need for re-engineering of the field, as it can use the existing infrastructure and wells, provided that facilities space exists topsides for installation of a reverse osmosis plant.