This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Typically, an effective waterflood will recover as much oil as the primary development phase with the minimal incremental investment if waterflood was catered for during FDP. In some cases, the only way to economically develop a field is to go straight to EOR. For example, heavy California and Canadian oil often require steam EOR from the beginning to be economic. This short class is intended for general audiences who want to be exposed to the various EOR options especially the Gas/WAG processes. Key risk and uncertainties often associated with waterflood and Gas/WAG projects and de-risking strategies will be discussed.
Jackson, A. C. (Chevron Corporation) | Dean, R. M. (Chevron Corporation) | Lyon, J. (Chevron Corporation) | Dwarakanath, V. (Chevron Corporation) | Alexis, D. (Chevron Corporation) | Poulsen, A. (Chevron Corporation) | Espinosa, D. (Chevron Corporation)
Reservoir management for an economically successful chemical EOR project involves maintaining high injectivity to improve processing rates. In the Captain Field, horizontal injection wells offshore have been stimulated with surfactant-polymer fluids to reduce surrounding oil saturations and boost water relative permeability. The surfactant-polymer stimulation process described herein enables a step change in injectivity and advances the commercialization of this application. This paper explains the damage mechanism, laboratory chemical design, quality control through offshore field execution and data quantifying the results.
Phase behaviour laboratory experiments and analytical injectivity models are used to design a near wellbore clean-up and relative permeability improvement. Three field trials were conducted in wells that had observed significant injectivity decline over 1-3 years of polymer injection. Surfactant and polymer are blended with injection water and fluid quality is confirmed at the wellheads. Pressure is continuously monitored with injectivity index to determine the chemical efficiency and treatment longevity. Oil saturation changes and outflow profile distributions are analysed from well logs run before and after stimulating. Learnings are applied to refine the process for future well treatments.
The key execution elements include using polymer to provide adequate mobility control at high relative permeability and ensure contact along the entire wellbore. Repeatability of success with surfactant-polymer injection is demonstrated with decreased skin in all the wells. The key results include the oil saturation logs that prove the reduction of oil near the well completion and improves the relative permeability to aqueous phase. The results also prove to be sustainable over months of post-stimulation operation data with high injectivity.
Injectivity enhancement was supported by chemical quality control through the whole process. From laboratory to the field (from core flood experiments to dissolution of trapped oil near wellbore), surveillance measurements prove that the chemical design was maintained and executed successfully. The enhanced injectivity during clean-up allows for higher processing rate during polymer injection and negates the need for additional wells.
The application of surfactant-polymer technology can rejuvenate existing wells and avoid high costs associated with redrilling offshore wells. This improves processing rate for EOR methods and can even be applied to waterflood wells to improve the injectivity, e.g low permeability reservoirs.
In this paper, we present a water-cut estimator utilizing the function approximation capability of an artificial neural network (ANN). The inputs to the ANN are optical sensor readings in a Red-Eye water-cut meter, which features the near-infrared (NIR) absorption spectroscopy technology. The initial training of the ANNwas done with a data set acquired from our multiphase flow-loop test facility, which was filled with live oil, water and gas. The test fluid stream was adjusted with good ranges of water-cut and gas-volume fractions which were supposed to cover the situations that can be foreseen in real production. However, clear discrepancies between the outputs of the ANN and the water-cut values from BS&W measurmentswere observedwhen the ANN was applied to actual production data measured by Red-Eye meters installed at two offshore wells. To address this issue and equip the ANN with self-adapting capability in real application, we propose a Bayesian approach to update the parameters of the ANN based on both initial flow-loop data and collected field data. The performance of the adapted ANN on both the data sets shows the effectiveness of the method.
The interest in on Carbon Capture and Storage (CCS) has increased over the last years with recognition of the ability of CCS to achieve a great reductions in CO2 emission as the fossil fuels will continue to be the main supplier for the world energy demand for the upcoming decades with no other alternatives are forecasted to replace them. The comparison between CCS and the other future alternatives or options relies mainly on the CCS cost -which is the main focus of this paper- removal of CCS deployment barrier in addition to the barriers and costs for the alternative options for CO2 emission reduction.
This study gives an insight comparison between the electricity cost for five different options of power generation including Combined Cycle Gas Turbines (CCGT) without and with CCS, coal and finally the nuclear power plants. In addition, it determines the ranges of fuel and carbon prices at which each option can be economically deployed
The recent coal CCS for Nth of a kind power generation plant cost estimates lie in the region of 60 to 100 $/ton of avoided CO2 which is higher than the previous CCS cost estimated and also greater than the accepted range of the forecasted carbon prices in the upcoming years. The higher costs of coal CCS would suggest the following: Coal CCS power generation plants is way less economical than gas ones for the range of carbon prices less than 60-100 $/ton of avoided CO2 Even at carbon prices higher than 100 $/ton of CO2, coal CCS power plants still produces higher cost electricity when compared to the gas CCS ones as long as the natural gas prices are still lower than 9 $/MBTU Coal CCS electricity costs are still higher when compared to a nuclear power plant option
Coal CCS power generation plants is way less economical than gas ones for the range of carbon prices less than 60-100 $/ton of avoided CO2
Even at carbon prices higher than 100 $/ton of CO2, coal CCS power plants still produces higher cost electricity when compared to the gas CCS ones as long as the natural gas prices are still lower than 9 $/MBTU
Coal CCS electricity costs are still higher when compared to a nuclear power plant option
It is widely believed that the CCS power plants (Gas or Coal) are not expected to be economical over the upcoming years, however introduction of subsidized forms of CCS are likely to take place. Also, CCS technology components are expected to be economically implemented in operations like Enhance Oil recovery (EOR), so, in this paper, an economic evaluation is provided for using of CO2 extracted from natural gas plant into EOR operations. CO2 separation cost in the natural gas processing industry is less than the capture cost of CO2 in power plants as a result of its high gas pressure and the fact that CO2 removal is mandatory to increase the value of a natural gas resource
On the other hand, this is not the case for the CCS of the most industrial emissions, as they are expected to be higher than those of power plants as a result of the smaller scale and wider distributed CO2 streams compared to power generation plants. This shows the importance of the realistic CCS cost estimation as a significant factor in the R&D projects and implementation trials that try to overcome the tackles that face the application of such promising technologies.
This paper describes a novel chemical injection system currently under development for long-term use in subsea oil and gas fields, and discusses the process being used to vet subsystems and components, and thereby increase the overall reliability of the system. Once proven and deployed, the system is expected to be a viable alternative to delivery of production fluids via umbilicals in deep water and with long stepouts from host production facilities. For decades, deepwater engineers have discussed a future in which oil and gas production systems that are typically located on floating facilities, would be placed on the seabed. The resulting subsea factory would include pumping, fluid storage, separation, power management, connections and controls all operating in the marine environment. While these technologies have proven to be reliable in the topside environment, and some have been used for short-term intervention, to date only boosting and separation systems, subsystems and components have been qualified for long-term installation on the seafloor. This paper details how the Technology Qualification Program, defined in the second edition of API RP 17Q, has been applied to qualify the novel subsea chemical injection system. The paper describes how the performance requirements were defined, together with their reliability implications, and provides examples of qualification activities.
Yudhowijoyo, Azis (University of Aberdeen) | Rafati, Roozbeh (University of Aberdeen) | Sharifi Haddad, Amin (University of Aberdeen) | Pokrajac, Dubravka (University of Aberdeen) | Manzari, Mehrdad (University of Aberdeen)
Crosslinked polymer gels have been widely used to overcome water and gas coning problem in the petroleum industry. Recently, nanoparticles are identified to have a potential of reinforcing the polymer gel systems by improving physical bonding and heat transfer properties in the gel structure. In this study, silicon dioxide and aluminium oxide nanoparticles were introduced to xanthan gum polymers that were crosslinked by chromium (III) acetate, to create polymeric nanocomposite gels with higher shear strengths. The gelation time and gel strength have been selected as main parameters to evaluate the effect of nanoparticle types and concentrations on the nanocomposite gels performance. The gelation time is measured until the onset of gelation or the moment when apparent viscosity starts to increase at 60°C. The gel strength is represented by the storage modulus (G’) after 24 hours of gelation at 60°C. Both parameters were measured by a rheometer, through constant shear rate and oscillatory tests respectively.
The addition of 1000 and 10000 ppm of silicon dioxide (SiO2) nanoparticles into a solution of 6000 ppm xanthan gum polymers that are crosslinked with 50000 ppm chromium (III) acetate caused insignificant changes in gelation time. Similar result was also reported when 1000 and 10000 ppm of aluminium oxide (Al2O3) nanoparticles was introduced into the polymer system. This suggests that when SiO2 and Al2O3 nanoparticles are introduced to xanthan/chromium (III) Acetate system for field application, no additives would be required to prolong or shorten gelation time to counter the nanoparticles addition. To analyse the gel strengths, the results from the oscillatory test were averaged throughout the frequency range, and it was shown that the addition of SiO2 nanoparticles decreases the average storage modulus from 75.1 Pa without nanoparticles, to 72.3 Pa at the nanoparticles concentration of 1000 ppm. However, the average storage modulus increased to 83.0 Pa and 94.7 Pa at higher nanoparticles SiO2 concentrations of 5000 ppm and 10000 ppm. The same trend was observed for the nanocomposite gels that were produced by Al2O3 nanoparticles. Similarly, the storage modulus decreased initially to 70.8 Pa at the concentration of 1000 ppm, then it increased to 89.9 Pa and 109.4 Pa at nanoparticles concentrations of 5000 pm and 10000 ppm, respectively. Hence, the nanoparticle-enhanced biopolymer gels showed insignificant changes of gelation time, and at the same time, they demonstrated up to 45% improvements in the gel strength properties when the nanoparticles concentration is higher than 5000 ppm.
In conclusion, the nanocomposite gels demonstrated reinforced bonding properties and showed higher gel strengths that can make them good candidates for leakage prevention from gas wells and blocking of water encroachments from aquifers into the wells.
Jové, Elbir (DuPont Specialty Products Operation Sarl) | Das, Supriyo (DuPont Specialty Products Operation Sarl) | Adamski, Robert (Shell Global Solutions US Inc.) | Gómez, Verónica (DuPont Specialty Products Operation Sarl)
Salinity of injection water plays a critical role in optimizing IOR/EOR methods, mainly in water flooding, low salinity water flooding and chemically enhanced oil recovery techniques, such as polymer floods. For such low salinity applications, preferred salinity is often between 1,000 and 5,000 mg/L TDS. On offshore platforms, this is achieved through blending permeate from low sulfate, high salinity (approximately 30,000 mg/l TDS) water train with desalinated water train (approximately 100 mg/l TDS). This practice typically requires two nanofiltration (NF) stages and one reverse osmosis (RO) stage which results in high footprint, heavy and complex blending manifolds. This study investigates the possibility of achieving the desired injection water composition employing a lower-footprint one pass assembly (i.e. without the need to blend permeates from parallel NF and RO trains) to produce the desired permeate salinity. The objective of the trial was to test a system providing a permeate TDS of 1,000 - 3,000 mg/L and sulfate levels lower than 10 mg/L. Such system should work with at least 20 L/m2h average fluxes and with a total recovery of at least 50 %. This paper discusses aninnovative way of arranging Nanofiltration and Reverse Osmosis membrane elements on offshore platforms in order to achieve the target salinity and sulfate concentrations for Low Salinity injection water Floods (LSF) and displays the results obtained during its testing in an industrial scale asset. The arrangement was operated during three months, showinga stable performance at an average flux of 20 L/m2h and with a recovery of 55%, using a configuration of seven membrane elements in series. Permeate water salinity obtained at this configuration was lower than 3,000 mg/L, maintaining low sulfate passage (<5 mg/L). Conclusions show the following benefits when using the innovative design:
Elimination of the blending system, thus reducing complex manifold and valves which will result in reduction of CAPEX and complexity. Achieving greater water recovery compared to operating separate RO and NF membrane systems. It is estimated that depending on the injection water requirements, there can be a reduction of up to 40% in footprint and weight of reverse osmosis and nanofiltration systems.
Elimination of the blending system, thus reducing complex manifold and valves which will result in reduction of CAPEX and complexity.
Achieving greater water recovery compared to operating separate RO and NF membrane systems.
It is estimated that depending on the injection water requirements, there can be a reduction of up to 40% in footprint and weight of reverse osmosis and nanofiltration systems.
The major challenge facing society in the 21st century is to improve the quality of life for all citizens in an egalitarian way, by providing sufficient food, shelter, energy and other resources for a healthy meaningful life, whilst at the same time decarbonizing anthropogenic activity to provide a safe global climate. This means limiting the temperature rise to below 2 C. Currently, spreading wealth and health across the globe is dependent on growing the GDP of all countries. This is driven by the use of energy, which until recently has mostly derived from fossil fuel, though a number of countries have shown a decoupling of GDP growth and greenhouse gas emissions from the energy sector through rapid increases in low carbon energy generation. Nevertheless, as low carbon energy technologies are implemented over the coming decades, fossil fuels will continue to have a vital role in providing energy to drive the global economy. Considering the current level of energy consumption and projected implementation rates of low carbon energy production, a considerable quantity of fossil fuels will still be used, and to avoid emissions of GHG, carbon capture and storage (CCS) on an industrial scale will be required. In addition, the IPCC estimate that large scale GHG removal from the atmosphere is required using technologies such as Bioenergy CCS to achieve climate safety. In this paper we estimate the amount of carbon dioxide that will have to be captured and stored, the storage volume and infrastructure required if we are to achieve both the energy consumption and GHG emission goals. By reference to the UK we conclude that the oil and gas production industry alone has the geological and engineering expertise and global reach to find the geological storage structures and build the facilities, pipelines and wells required. Here we consider why and how oil and gas companies will need to morph into hydrocarbon production and carbon dioxide storage enterprises, and thus be economically sustainable businesses in the long term, by diversifying in and developing this new industry.
Water Alternating Gas (WAG) injection is a widely practiced EOR method for many reservoirs. One drawback of WAG is the decreased injectivity when gas, often CO2, is injected into a previously water-flooded reservoir, and a further decline of injectivity is observed as water and gas injection are alternated. We present a workflow which allows the estimation of injectivity decline using pore scale displacement simulations and reservoir simulations.
In this approach, we use a multiphase Lattice Boltzmann method to directly simulate the alternating water-gas injection at pore scale resulting in a relative permeability curve for each injection phase. The simulation input accounts for injection rate, fluid properties and spatially varying wettability for each cycle during WAG. The final distribution of fluid phases in pore space of each displacement test is used as the starting point for the next displacement cycle. This enables the simulation of imbibition-drainage cycles. Any hysteresis effects present are typically captured in the resulting relative permeability curves. These are then used in a reservoir model to obtain an injectivity index for each injection phase.
We observe a strong decline of water relative permeability after the first gas injection cycle in an oil-wet rock. Detailed analysis of the fluid phases, in particular the water phase, shows that water is well connected after the initial water flood before gas injection. As gas is injected large water blobs are partially displaced and their size significantly reduced. For this wettability scenario, water and gas are competing for the large pore system. We find that capturing the hysteresis effect in a WAG requires the direct simulation of the displacement process, in particular known pore scale phenomena such as trapping and retraction.
The novelty of this approach is to directly capture the hysteresis effect of a WAG workflow in a direct simulation of displacement at pore scale. Emphasis is put on a detailed analysis of the multiphase displacement, including visualizations and an explanation for why the injectivity during WAG is reduced, namely, water and gas are competing for the same pore space. The presented workflow enables an a priori estimate for injectivity losses in a WAG EOR approach.