Among the various flow assurance problems that the petroleum industry faces, the deposition of paraffin waxes on to the wall of the pipeline is the most challenging. The challenge arises when the crude oil temperature decreases below the wax appearance temperature (WAT) which leads to the wax crystal in the crude oil to crystallize. An efficient method in remedying paraffin wax deposition is the utilization of chemical inhibitors. However, currently used chemical inhibitors are costly and environmentally harmful if a spillage occurs. Therefore, the use of biodegradable or environmently friendly inhibitors as potential chemical inhibitors are being studied by various researchers. This study investigated oleic acid, poly (ethylene-co-vinyl acetate) (EVA) and triethanolamine (TEA) as inhibitors that perform based on the van der Waals intermolecular interaction between the main wax component molecule eicosane C20H42 using the molecular dynamics simulation (MD) procedure via Material Studio 8.0 software package. In order to analyse the desired structural property which is the Radial Distribution Function (RDF), COMPASS force field was used. The RDF and g(r) function portrayed the functional atoms which aid in inhibiting the agglomeration and crystallization of the wax crystal formation. The presence of a carbonyl oxygen in oleic acid plays a vital role to inhibit the wax formation through the van der Waals interaction between active hydrogen atoms in eicosane molecule. Therefore, the chances of wax inhibition in eicosane is higher by introducing oleic acid as an inhibitor as compared to EVA and TEA. The results were then validated experimentally utilizing a cold finger technique under static condition.

CO 2 capture and storage (CCS) is an important method to mitigate greenhouse gas (GHG) emissions by injecting CO 2 into deep geological formations such as depleted hydrocarbon, unminable coal beds, and deep saline aquifers. However, due to the density variations between the supercritical CO 2 and formation water, CO 2 migrates upwards to the atmosphere. The risk of this CO 2 migration can be prevented by different trapping mechanisms (e.g. structural trapping, capillary trapping, dissolution trapping, and mineral trapping). The trapping efficiency of these trapping mechanisms is highly influenced by various factors including CO 2 injection scenarios, injection well configuration, reservoir wettability, reservoir heterogeneity, reservoir temperature, and formation water salinity. One of these factors, which has received little attention, is the caprock type. Although caprock wettability has been investigated previously as a factor affecting residual and structural trapping capacities, the effect of caprock type on mineral trapping efficiency has not been addressed yet. Thus, in this paper, we studied the impact of caprock type on geochemical reactivity and mineral trapping capacity by simulating a permeable sand reservoir overlying by three different semi-permeable caprock layers with different mineralogy (i.e. sandstone, siltstone, and shale). The Chemical Composition of these different caprock samples was measured using quantitative X-ray diffraction (XRD) instrument. XRD results indicated that siltstone and sandstone samples consisted mainly of quartz (~50wt %), while shale sample consisted mainly of illite (33)% and quartz (31%), in addition to few other smaller fractions of Illite, Chlorite, Albite, K-feldspar, Hematite, Ankerite, and Calcite. Our simulation results show that caprock type has a significant effect on geochemical reactivity and the associated mineral trapping mechanism. The results clearly indicate that the geochemical reactivity of siltstone caprock is relatively high, compared to shale and sandstone caprock cases. Furthermore, the results show that siltstone caprock scenario has the highest mineral trapping capacity, followed by shale and sandstone caprock scenarios, respectively. Moreover, the results indicate that sandstone caprock has the most increase in reservoir porosity and permeability. Thus, we conclude that the caprock mineral composition plays important roles in the geochemical reactivity and the associated mineral trapping of CO 2 .

The early development of offshore heavy oil fields mainly adopts the method of large well spacing and multilayer combined production development. After entering the high water cut period, it is faced with the problems of low oil production rate, rapid production decline and low recovery factor, and lack of experience of development adjustment in high water cut period, which result in oilfields in low level development stage for a long time. Taking Qinhuangdao 32-6 oilfield as the target area, the study of stratigraphic subdivision and well pattern adjustment in high water-cut period was studied by using laboratory physical experiments and reservoir numerical simulation, and the technical limits of stratigraphic subdivision for offshore heterogeneous heavy oil reservoirs, well pattern adjustment model and horizontal well layout technology were defined. The results show that when the permeability ratio is greater than 3 or the reservoir viscosity ratio is greater than 3, the interlayer interference coefficient is more than 0.2, and the stratified development should be carried out. For strong heterogeneous reservoirs, the basic inverse nine-spot well pattern is adjusted to a five-point horizontal well pattern by infilling horizontal production wells between injection and production wells, and the spacing of injection-production wells is reduced from 350 m to 220 m, and the volume sweep coefficient is increased by 26%. For the bottom water heavy oil reservoir with the viscosity of 260 mPa·s, the horizontal well can greatly improve the initial production and cumulative oil production of the single well by optimizing the distribution of wells with interlayers (parameter: interlayer permeability, distribution area and distribution location) within the reservoir. When the cumulative oil production of horizontal well reaches 50, 000 m 3 , the height of the oil column can be pushed down to 7 m. Based on the above research results, a new model for development and adjustment for horizontal wells for development adjustment of horizontal well stratification system in high water cut period has been formed. It was applied to QHD32-6 oilfield, and 124 horizontal wells have been implemented. After adjustment, the oil production rate has increased 2.5 times, the recovery rate has increased by 12.8%, and the oilfield development effect and economic benefit are greatly improved, which can provide an important reference for the development adjustment of similar oilfields in high water cut period.

The low-salinity polymerflooding (LSPF) is a promising enhanced oil recovery (EOR) method with a synergetic effect that combines advantages of the polymerflooding and the low-salinity water flooding. Since polymers are highly sensitive to both pH and salinity of the formation water, the efficiency can be deteriorated when the LSPF process is adopted to carbonate reservoirs with highly acidic or high-salinity formation water. In order to maximize the LSPF efficiency, properties of the injection fluid need to be properly designed in terms of salinity, ion composition, and ion concentration, while taking the polymer properties into account. In order to investigate efficiency of the LSPF for a carbonate oil reservoir that contains "acid" formation water, a set of coreflooding experiments was performed with low-salinity polymer solution in carbonate rock specimens containing acidic or neutral formation water. Not only were the polymer retention and permeability reduction by the polymer adsorption phenomenon analyzed with the measured pressure difference and ultraviolet-visible spectroscopy, but the wettability alteration during the LSPF was also examined by the relative permeability and contact angle changes. In addition, the enhanced oil recovery by the LSPF process was measured to identify the efficiency. Based on the calculated permeability reduction, it is found that the reduced magnitude was smaller for the diluted seawater than the seawater and river water, although the river water has the lowest salinity. This is because its SO 4 2- ion content, which interferes adsorption of the polymer molecules on the grain surface, was lower than that of the others. Meanwhile, amount of the permeability reduction was larger in the acidic formation water than in the neutral formation water, as the polymer adsorption is facilitated when the formation water has a low pH value. On the other hand, the wettability alteration to water-wet in the diluted seawater is greater than in the seawater due to its low salinity. In spite of the lowest salinity, however, the results indicated the alteration of the river water was the smallest due to the extremely low SO 4 2- ion content. Although the same alteration behavior was observed in the neutral formation water, it appears that the magnitude of the wettability alteration by the SO 4 2- is higher for the acidic formation water. Therefore, we concluded that the wettability alteration was mainly affected by the SO 4 2- ion contents of the injection water. Consequently, the diluted seawater with the high SO 4 2- content yielded the best oil recovery for the acidic carbonate, as it prevents the permeability reduction and facilitates the wettability alteration. For an acidic reservoir, it is found that low-salinity water such as river water is not always desirable as an injection water unless it contains enough SO 4 2- ion. Thus, not only the low salinity, but the SO 4 2- ion content is also significantly important for the EOR efficiency, particularly in "acidic" reservoir.

Continuous efforts are made in drilling engineering to identify and develop advanced tools and technologies to maximize rate of penetration (ROP). Optimization of ROP has a major impact on both the reduction of the cost in terms of cost per foot and well delivery. Numerous correlations, methods, designs, models, and tools for ROP optimization are available in literature but rarely are applied in drilling operations. This paper introduces a robust methodology aiming to optimize the rate of penetration without inducing any associated wellbore stability problems. The objective of this paper is to detail the methodology and the effectiveness of the technique introduced. We report performance indicators for a trial well drilled using the novel approach and compare the findings with a conventionally drilled offset well. The drilling parameters for a challenging horizontal hole section were collected and analyzed to evaluate their effect on ROP performance. The drilling parameters selected are from corresponding hole sizes, formation and mud types with respect to the offset well for a consistent comparison. The proposed approach contributed to an enhanced well drilling performance by more than 40% and was instrumental in mitigation of stuck pipe incidents. In this paper, we introduced and verified a novel technique to maximize the rate of penetration (ROP) by optimizing the drilling parameters (RPM and WOB). As long as the CCA is less than 0.05, the proposed workflow in this study can be used to determine an optimized ROP in conjunction with a minimized DSE yielding ideal RPM and WOB values thereby reducing the cost per foor drilled. Evidence of the efficiency of the proposed procedure is provided by comparing the ROP and DSE measured for a horizontal section drilled employing the technique with data for an offset well drilled in a non-optimized fashion. Compared to the latter case, we reported a 44% improvement in ROP and a 48% reduction in DSE.

The mutual converting between production and injection well can be applied to change the directions of streamlines to improve the sweep efficiency of zone with high residual oil. How to improve the oil recovery by efficiently developing the remaining oil is a key issue for ultra-high water-cut reservoir. Therefore, based on a realistic reservoir selected from Shengli Oil-field, a model is presented to investigate the effects of different converting patterns on ultra-high water cut reservoir. In this work, we built the model in Eclipse of Schlumberger according to the real well pattern and reservoir conditions. The residual oil distribution after water-flooding under ultra-high water cut was studied. Then, to obtain the optimal oil recovery, we investigated four well converting patterns, including the distribution of modified streamlines and final oil recovery. Moreover, we investigated the effects of water cut which is the time to convert and permeability ratio on residual oil recovery. All patterns and the model is described in detail to permit readers to replicate all results. According to the simulation results, the shape of residual oil distribution of traditional five-point pattern is like a cross which is around the production well. Comparisons of oil recovery of four converting patterns are presented. The optimal case is the pattern which applies well converting in an interval way, arranging one injection well between two production wells. This interval way is able to let streamlines sweep more areas with high oil saturation. Whether high oil recovery can be received also depends on two significant parameters-water cut and permeability ratio. For water cut, there is an optimal number when applying this method. In this study, the converting should be applied when water cut is 93%. For permeability ratio, the higher it is, the higher oil recovery we can have after applying the converting. Both two parameters are combined to obtain the best water cut to convert with different permeability ratios. Due to high cost of many EORs like chemical flooding, the novelty of this work is in the ability to provide a more cost-effective and convenient method to address the low oil recovery of high water cut oil-fields.

Flow back fluid during matrix acidizing in carbonates reservoir has the characteristics of complex composition, variable physical and chemical properties, high content of crude oil and suspended solids. If discharged directly to the ground, it will cause serious environmental pollution and waste resource. A novel and environmentally friendly treatment method to solve this problem has been developed by optimizing surface flow back process, selecting chemicals, modifying filter types and equipment structure. The overall treatment strategy is to separate oil, gas, water and solid phase, inject dehydrated crude oil into pipeline, ignite gas, discharge water after meeting the requirements of industrial wastewater discharge standard, and treat solid phase harmlessly. Some problems such as emulsification, foam fluid and organic scale have been solved by optimizing acid recipe and adopting new chemicals. This novel technique successfully solved the environmental pollution problem and has high economic benefits.

The efficiency of hydrogen sulfide scavengers directly injected into gas streams is often compromised by short contact times due to space limitations on offshore assets. The use of static mixers is often employed to increase the efficiency of gas-liquid mixing. The performance of two commercially available hydrogen scavenger products were assessed in the laboratory utilising a specially fabricated test chamber designed to mimic a static mixer. A continuous feed of both gas and a liquid scavenger solution were mixed through a glass bead static mixer. The liquid scavenger was atomized into the gas prior to traveling through the bed. The impact of dose rate, water content, carbon dioxide and contact time were assessed on the scavenging efficiency and kinetics of two triazine chemicals used to sequester H2S from a gas stream containing 180 ppmv H2S in nitrogen, to achieve a target H2S concentrations of <10 ppmv. Efficiencies derived from the test apparatus revealed that the formulation based on the ethanolamine triazine chemistry performed significantly better than the methylamine triazine product at the two contact times of 3 and 25 seconds. The equilibration time required to reach the target concentration were significantly longer at the shorter contact time, and unachievable without the static mixer. The dosages of scavenger required to reduce the H2S concentrations from 180 ppmv to 10 ppmv were much higher than theoretical dosages. The addition of water to the scavenger mixtures was found to increase the efficiency of the ethanolamine scavenger but decrease the performance of the methylamine based triazine. The importance of atomisation of the scavenger onto the fixed bed was reinforced by the dramatic reductions in performance associated with a lack of atomisation. The presence of CO2 had no significant impact on the scavenging efficiency but had a kinetic impact and reduced the time to achieve the target concentration.

Currently, most of offshore platforms are equipped with gas turbines to fulfill their power requirement and consequently produce CO 2 emissions as a by-product. The energy efficiency of the asset is a key factor in reducing their carbon footprint impact. Numerous ways can be considered within the process and utility systems to improve the energy balance. This paper will investigate the possibility to exploit the available hydraulic energy onboard offshore platforms to transform it into electrical energy. Part of the recoverable hydraulic energy is found in pressurized pipes where the flow is in charge or in other words under hydraulic pressure. The aim is to develop a novel turbine that will be optimized for water disposal energy recovery on offshore platforms. Hence the objective is to install a turbine to replace a conventional valve to maintain and regulate the pressure as well as generating electricity. In close collaboration with TechnipFMC, ICube laboratory (Strasbourg, France) is completing a development program for such an hydraulic turbine. This paper describes some outcomes of this comprehensive study performed by experimental engineers and researchers in the hydraulic discipline with the support of engineering integration by TechnipFMC.

With most oilfields at Bohai Bay enters into middle and late waterflood development stage, the oilfields have high water cut but low recovery degree. Chemical methods of enhanced oil recovery (CEOR) such as polymer are applied. However, the degradation and retention of polymer inside reservoir make it less attractive. Moreover, due to serious over-standard injected water quality or low-medium reservoir permeability, the CEOR are confronted with many challenges such as high injection pressure, difficulty in injection. Therefore, a new oil displacement technology of nanometer dispersion with good injectivity, dispersion stability and strong oil displacement characteristics is proposed. The focus of this study is to indentify the stimulation mechanism of nanometer dispersion and reveal its possibility for EOR in Bohai oilfield. A set of experiments, including interfacial tension, contact angle, wettability, viscosity and core displacement, were conducted to investigate the effects of nanometer dispersion on the recovery of crude oil in Bohai Q oilfield. It was observed that nanometer dispersion fluid at the concentration of 0.5 wt.% can: 1) reduce the oil-water interfacial tension to 10 −3 level; 2) decrease the oil-water contact angle from 55° to 9 °; 3) reduce the crude oil viscosity from 259 cp to 132.8 cp, with a viscosity reduction rate of 48.7%; 4) improve the oil washing efficiency of oil sand to as high as 79.1%; and 5) improve the oil recovery rate of core plugs by 25%∼46% compared with water flooding. The lab-scale test was then extended to field-scale test. A pilot field test was conducted in Bohai Q oilfield, which was very successful, and obvious effect on controlling water and increasing oil production was obtaineded, with an oil increment of 6158m 3 . Laboratory and field test results show that the nanometer dispersion, as a new EOR technology, could considerably increase oil recovery and has a wide application prospect.

Multiple thermal fluid huff and puff, which uses nitrogen, carbon dioxide and hot water as thermal medium, has achieved a high increase of oil production rate in BN reservoir, a heavy oilfield locating at Bohai Bay. Six wells have completed two cycles of thermal huff and puff. Comparing to initial conventional production using natural energy, the periodic well production in first cycle increased to 1.6 times and the annual production rate of the whole reservoir increased from 0.4% to 0.7%. However, due to high formation oil viscosity (413∼741mPa•s) and strong heterogeneity, the injected fluid breakthrough happened three times in the second cycle. On one hand, the well production rate didn't gain an obvious increase because of the heat loss, on the other hand, the surrounding wells which were broken into had to be shut down. Consequently, the annual reservoir production rate was only 0.5%, which was much lower than project design. There is an urgent need to find a suitable solution to the injected thermal fluid breakthrough. The most effective way to restrain the fluid breakthrough is injecting the thermal fluid into all the thermal recovery wells simultaneously, which is not realizable due to the offshore platform space limit. Combinatorial method with thermo-gel treatment have been optimized for more cycles of thermal huff-puff. Thermo-gel polymer and cross-linking agent spontaneously gel when they reach a critical temperature, which is configured between original reservoir temperature and reservoir temperature during thermal huff period. Thermo-gel was injected ahead and entered the high permeability channels mainly. With the plugging effects, the fluid breakthrough was prevented. Meanwhile, the thermal fluid permeated into low permeability zone where remaining oil concentrated, resulting to higher efficiency of injected heat. Thermo-gel treatment was carried out for the rest three wells in the second cycle. Around each of the three thermal injection wells, there were 2∼3 wells that could have fluid breakthrough and only one surrounding well happened. Compared with the first three wells in the second cycle, the periodic oil increment of the last three wells increased to 2.6 times and the average effective period extended 105 days. Field practice showed a positive synergistic effect between thermal huff-puff and thermo-gel treatment. In the help of thermo-gel treatment, incremental oil production for single well has reached 1.58×10 4 m 3 in the past few years. Our experiences show that such thermo-gel treatment assisting technology for thermal recovery is effective for enhancing oil recovery of heavy oil fields and meets the demand of high speed development for offshore oil fields.

The floating Gas industry is growing rapidly. As with all sectors in boom times, the focus is firmly on output. We need to ensure safety, compliance and profitability of what are high value, complex assets some of which operate close to high population densities. The speed of growth must be matched by an equivalent effort to maintain asset integrity while continuing production. Put simply, existing inspection and maintenance methods are not fit for purpose. This paper describes a joint industry approach for addressing these challenges that has proved successful for FPSOs. The industry needs to operate with high levels of asset integrity, with a programme of continuous improvement and with a long-term planning view. Effective Asset Integrity programmes are a key part of the strategy, and it is widely agreed that better use of data and robotics will help reduce unnecessary work and human risk. The HITS (Hull Inspection Techniques and Strategy) JIP, part of the FPSO Forum, has a membership made up of oil majors, service providers, classification societies and regulators. It has encouraged the development of new technologies, which have significantly improved safety and reduced operational costs. Drawing on experiences of other industries, the HITS JIP has driven innovation; safer, more cost-effective, more efficient technology, which has led to less impact on core operations of floating production assets: these include: The gas industry provided a means of placing nuclear industry miniature cameras into sea chests and isolation valves so that they can be inspected without affecting operations; Hull inspections were improved using deck launched, remotely operated underwater vehicles (ROVs) adapted to carry out cavitation cleaning of sea chest inlet grids, impressed current cathodic protection (ICCP) anodes and points of structural interest, such as bilge keel end connections; The forestry industry provided the idea for chain crawlers for inspection and repair of deep-water moorings; From the Nuclear industry, robotic inspections using high performance cameras, adapted to be inserted through Butterworth hatches or purpose-fitted ports in the deck enabling general and close visual inspection to meet regulatory requirement without the need for confined space entry; To protect the hull, diverless ICCP systems, deploying retractable anodes through the hull; and For pressure systems, using data more effectively; inputting inspection data to confirm fitness for service to an agreed level of confidence. This paper describes a joint industry approach for addressing these challenges that has proved successful for FPSOs. It will describe the steps that have already been taken to create an industry wide group including operators, class, regulators and service providers, to agree the primary challenges and to encourage development of solutions in a cost-efficient way. It will describe how innovations developed and proven in the FPSO and other sectors can be successfully introduced to this sector.

In the offshore oil and gas exploration business, safety, reliability, environmental concerns and costs play vital roles. Gas compressors have been widely used in offshore applications to meet a wide range of duties such as gas lift, injection, export and separation. Traditionally, gas turbines have been chosen as the driver for gas compressors. However, with the advancement in technology, electric motors are now being utilized as an alternate solution to drive these gas compressors. The advancement in offshore power generation and power from shore technologies has shown that a centralized offshore power generation utilising larger prime movers based on electric motors or aero derivative multi-spool gas turbines provide advantages in both size and weight. This paper explains selection of the drive for gas compressors specifically making a choice between gas turbines and electric motor drives. Both technologies are proven to be mature are able to cater for various power ranges, applications and environments. Nevertheless, the selection process for offshore gas compressor drivers is still considered a grey area due to various aspects that influence and affect the selection of driver for an optimized offshore solution. The harsh nature of offshore locations warrants robustness to ensure high reliability and availability, minimal maintenance, clean emissions, small footprint, low fuel consumption and low initial investment. A parametric study based on an actual operating offshore facility was performed to evaluate the advantages and disadvantages of each driver type. An existing offshore facility that utilized gas turbines as the driver for both power generation and gas compression was set as Base Case for this study. The Alternate Case required that the gas compression system utilize electric motor drives as the driver and upsizing of the power generation system to cater for the motors electrical load was now increased. The optimum driver was determined based on cost (CAPEX and OPEX), reliability, availability, efficiency, power requirement (electrical system, power generation & distribution), dimension, layout and emissions. The findings of this study are expected to be a benchmark reference for driver selection for future offshore gas compression systems of similar operation and power range.

Ocean Thermal Energy Conversion (OTEC) has garnered international interest as a clean and sustainable source of secondary power generation, without impacting the environment and regardless of seasonal weather conditions, for offshore Oil & Gas (O&G) processing facilities. This is considering the suitability of waste heat extraction from existing offshore deepwater Oil & Gas platforms as a complementary application for integrated OTEC modules (hereafter abbreviated as i-OTEC). Such an application is possible with the availability of cold seawater drawn from extended seawater lift caissons or deepwater intake risers. This study investigates, in detail, the various refrigerants that are feasible alternatives to Ammonia (NH3) for a 1MWe i-OTEC scheme. Anhydrous NH3 or R717 was initially selected as the refrigerant for the aforementioned i-OTEC scheme which is modelled based on an Organic Rankine Cycle (ORC). It is widely accepted that R717 is the ideal refrigerant for this application due to R717's high enthalpy change during expansion. Although R717 is classified toxic, R717 emissions generally do not create environmental problems, and is detrimental to health only upon presence of R717 at a Short Term Exposure Limit (STEL) of 35ppm. For comparison purposes, other alternative refrigerants were also studied; focusing particularly the risks associated with the refrigerants including toxicity, flammability, asphyxiation, reactivity and physical hazards. Hence, the selection of the refrigerant was a major factor in the design as it provides the basis for further investigation. Shortlisted alternatives, which include R1234yf, R410a, R134a, R290 and R32, were additionally assessed on multiple factors including expected enthalpy gain from the Rankine cycle, circulation flowrate, equipment sizing, hazard classification of refrigerants, compliance to international/local exposure standards, handling and storage of refrigerants. It is identified that the aforementioned refrigerants are possible alternatives to R717 - but with some drawbacks from a thermodynamic performance perspective, and the fact that some of these refrigerants would be rendered obsolete in various industries. Consideration of the next generation of refrigerants must balance out factors such as public awareness, manufacturers availability, safety aspects and environmental concerns. The latest refrigerant with minimal environmental impact is R1234yf and it has been slowly accepted in the HVAC and motor industry. Additionally, the turboexpander-generator shaft sealing was identified as the major source of refrigerant emissions during normal operation. Hence, various shaft sealing solutions were also scrutinized to assess the viability of utilizing R717 as a refrigerant whilst still fulfilling safety and emission requirements.

The combination of seismic exploration technology and drilling engineering forms the seismic measurement while drilling (SWD) technology, which can provide conventional borehole seismic measurements in real time while a well is being drilled. Just as conventional while-drilling services, it is effective and efficient in supporting drilling decisions. With measurement device positioned near the drill bit, real-time processing of downhole seismic data can increase the safety and efficiency to the drilling work. We study the problem in a vertical layered media by using while-drilling measurements, the artificial signal emitted by the seismic source is recorded by surface / downhole sensors, then the direct arrival traveltimes could be obtained after basic data processing. Using the traveltimes as the input of a Bayesian inversion procedure for the estimation of the bit position and the velocity model, the engineers would get the estimated values and their associated uncertainty, which could be used to predict the formation geology ahead of the drill bit and to find the lithology, fracture and abnormal pressure in front of the drill bit in time. Conventional system has been available to the petroleum industry for some time, with seismic sources located on the surface and receivers in a borehole. The downhole detection device for SWD is mainly composed of three sets of geophone arrays, which are distributed in different axial direction, as well as the corresponding control and processing circuit. We test the inversion strategy on realistic cases in the laboratory and oilfield. According to functions, the electronic circuit is divided into main control and communication unit, signal acquisition unit, storage unit, and power detection & data play back unit. By cross-correlation processing of the direct seismic wave and the reflected waves from formation boundary, the performance of the systems were well proved. Based on theoretical analysis, system development and experimental study, this paper will highlight the technical development.

The well construction operation in the pre-salt reservoirs of Santos basin faced great challenges such as the drill string stuck in big-thickness salt formation (more than 2000m) and low penetration rate in the reservoir formation from the beginning of X. Project. The average actual well construction duration of four wells completed in 2015 was 7 days behind the planed period caused by the above-mentioned problems. The well construction cost was more than the approved budget due to the delayed well construction duration. So efforts was concentrated to integrate drilling technology in ultra-deep water to solve drilling challenges in the pre-salt reservoirs to decrease well construction duration and increase exploration and development benefit. This paper presents an integrated drilling technology to solve drilling challenges in pre-salt reservoirs of ultra-deep water. The combination of near bit reamer stabilizer and synthetic-based mud can prevent the salt formation creeping and decrease the drill string stuck frequency. The optimization of drilling parameters based on mechanical specific energy concept can clearly identify the transfer from the anhydrite formation to the salt formation and drilling penetration rates can be improved in salt formation by optimizing WOB, rotate speed and pump rate, etc. The combination of MPD, turbine drill and impregnated bit can control the mud losses and increase the penetration rates in the carbonate reservoirs which possess poor drillability. All the above-mentioned drilling technology has been applied in two wells and successfully solves the drilling challenges in the pre-salt reservoirs of X. Project. The combination of near bit reamer stabilizer and synthetic-based mud has decreased the drill string stuck NPT from 11.7d to zero in two wells of X. Project. The average ROP record of the two wells by use of the integrated drilling technology is 24.6 m/h that has been improved 3.4 times comparing the completed four wells in 2015. The drilling duration for 2062m salt section has decreased to from 14 days to 7 days which saved about 14 millions dollars for the two wells. The average ROP in the reservoir formation of the two wells has been increased to 3.45m/h which was about 1.5 times of the four wells' average ROP completed in 2015. The reservoir section has been completed 4.6 days ahead of the planed duration and the comprehensive drilling cost has been saved 5 millions. The integrated drilling technology in pre-salt reservoirs in ultra-deep water made the average well construction duration of the two wells finished in 2016 have decreased to 111 days, however, the average well construction duration of the four wells completed in 2015 was 162 days. The fastest record of the one well's construction duration was 76 days establishing a new benchmark in pre-salt reservoirs in ultra-deep water. The method to solve well construction challenges in the pre-salt reservoirs of Santos Basin of this paper presented will make a reference for deep water salt formation drilling and offshore oilfields high efficiency development.

Hydrocarbons are the major source of energy. Its increasing demand has made the hydrocarbon exploration go beyond the shore. Offshore Rig power requirements are higher compared to onshore rigs. Diesel Generators are conventionally used for the power requirements of offshore rigs. This paper aims to suggest an idea to use the renewable sources of energy (mainly tidal energy) for energy generation in offshore. The idea is to have a Hybrid energy system, in which both the renewable and non-renewable sources of energy can co-exist together in a symbiotic relationship. The energy harnessed from tidal-waves shall be used to meet the power requirements of offshore rig alongside the diesel generator. This would result in overall more efficient and cost effective energy generation. Wave energy would be harnessed on wave energy harvester system platforms installed around the offshore rig set-up; on which the motion of floats would be transferred via hydraulics into rotation of generator which will produce electricity. The energy generated would be transferred to rig via wires and can be stored in batteries for transportation to land to meet other power requirements. An analysis of tides/waves generation is detailed. Available data for prototype of Wave Star Energy harvester is examined followed by Monetary-Energy Capacity analysis. SWOT analysis and environmental impacts are discussed. Various parameters affecting the Tidal energy generation are scrutinized. There is a need of an alternative source of energy in offshore rigs because of high environmental impact of diesel generators and other problems associated with it. Given the current global scenario and advancements in Electric automobile market, there is an exigency for a Hybrid energy system to meet the upcoming energy needs and boost the Global Energy Infra.

As waterflooding has become one of the most favorable approach for secondary recovery globally, understanding flood front behavior and reservoir sweep becomes even more pertinent to maximize recovery. To monitor the effectiveness of a waterflood program, chemical tracers are often deployed for enhancing surveillance techniques. This paper presents a classic example of value creation from the existing tracer database with the demonstrated workflow of the Residence Time Distribution (RTD) method in tracer interpretation applied in a mature waterflood field. The analytical study conducted was in a complex oil rim field located in East Malaysia. As a five-year sampling programme was initiated for this field, a substantial amount of sample and corresponding tracer response data allowed the field to be a strong candidate for tracer RTD data analysis. Injection was carried out via smart wells into 28 zones and samples were taken on routine basis from monitored producers. Breakthrough of unique tracers coupled with low detection levels from the vendor laboratory were utilized as a foundation for constant waterflood optimization. Flow geometries and reservoir continuity between each injector-producer pairing were measured in detail through analysis of chemical tracer response curves. Apart from immediate injector-producer communication upon first tracer breakthrough, a detailed study on water flood performance based on the RTD method allowed the pore volume swept, mass recovered from each section and quantification of heterogeneity to be determined. Flow geometry and reservoir continuity between each injector-producer pairing were also measured allowing identification of thief zones, out of zone injections, vertical communication between layers, and behind casing flow. As a result, the information gathered allowed the optimization of each injection zone based on the outcome of the tracer response at the respective producers. This information has proven beneficial to the reservoir surveillance team allowing insightful decisions to be made upon subsequent opportunities for production and water flood optimization.

This paper investigates the effect of rock permeability on foam transport in porous media both at the core-level and at the field level for enhanced oil recovery (EOR) applications. Foam offers promise to simultaneously address the issues that limit the overall oil recovery efficiency of water-alternating-gas (WAG) process such as viscous fingering, gravity override, and reservoir heterogeneity. However, in the literature, limited foam data were reported using actual reservoir cores at harsh conditions. In this paper, a series of methane (CH 4 ) foam flooding experiments were conducted in 3 different actual cores from a proprietary reservoir at elevated temperature. It is found that foam strength is significantly correlated with rock permeability. We calculated the apparent viscosity based on the measured pressure drop along the core samples at steady state. The calculated apparent viscosity was found to be selectively higher in cores of high permeabilities compared to that in cores of low permeabilities. We parameterized our foam system using a texture-implicit-local-equilibrium model to understand the dependence of foam parameters on rock permeability. In addition, we established a 2-layered heterogeneous model reservoir in the Shell in-house simulator called MoReS (Modular Reservoir Simulator) to systematically study and compare the driving forces for fluid diversion during foam flooding at the field level including the gravitational force, the viscous force, and the capillary force. During the WAG process, gravitational force kept the gas from sweeping the lower part of the reservoir. The gravity can be overcome by viscosifying the gas with surfactant solution. In addition, capillary pressure which hinders the gas from entering the low permeability region can actually redistribute the two phases during foam EOR and improves the sweep efficiency. It is concluded that foam can effectively improve the conformance of the WAG EOR in the presence of reservoir heterogeneity.

Since 2014, the CO2 emissions due to fossil energy combustions have been more or less stable, but compared to 2016 the emissions shall increase from 2% in 2017. [ 3 ]. The peak shall rise to 36.8 Billion of tons in 2017. Energy, with 66% of emissions, remains one the most important contributor to the gas emission sector.