CHOPS is not suitable for all heavy unconsolidated sandstone (UCSS) reservoirs. Recovery factors greater than 20% of OOIP are unusual; values of 10 to 16% are more common. However, combining CHOPS with other production technologies may increase ultimate recovery factors. Through yield, dilation and liquefaction, and perhaps through channeling, CHOPS creates a large region of greatly enhanced permeability. Is it possible to exploit this with other technologies?
Selecting the best tool for a specific type of reservoir condition is a crucial part of a fluid sampling job. Moreover, uncertainty in sample quality increases when the fluid phases are miscible. On a recent logging job, a formation tester was used to acquire water samples across a zone drilled with water-base mud (WBM). We examine the performance of several probe configurations (both existing and prototype) under equivalent reservoir conditions to quantify and optimize filtrate cleanup efficiency. The study is carried out using a compositional simulator for a water-saturated reservoir invaded with blue-dye tracer included in WBM filtrate.
History matching of field measurements allows the calibration of the model for further modification to account for a variety of reservoir conditions. Complex tracer dynamics of a blue-dye WBM invading a water-saturated formation and fluid pumpout are accurately and expediently modeled using a flexible numerical algorithm to account for different probe types and tool configurations. Under normal operating conditions, the chosen formation tester would have taken around one hour to clean the filtrate contamination to a target value of 5%. On the other hand, the best choice was the Focused Elliptical Probe, for which fluid cleanup would take less than 40 minutes. Additionally, a different tool configuration with a combination of multiple probe geometries spaced radially around the tool would provide faster cleanup times of only 32 minutes, thereby saving rig time.
We rank eight formation testing tools designs under equivalent reservoir conditions. The examples highlight the importance of probe geometry and configurations together with reliable and expedient numerical modeling during the pre-job phase to reduce cleanup time in anticipation of complex reservoir conditions. Furthermore, numerical simulations compare the fluid cleanup efficiency for various commercial formation-testing probes together with innovative probe designs that could potentially lead to a new tool or probe development. Perfecting both probe geometry and fluid pumping schedule is the most important output of our study.
Norwegian suppliers Framo, Maritime Partner, Norbit Aptomar, and NorLense have come together to create the Oil Spill Recovery Vessel Group to offer a complete oil-spill-response solution. Workers who were likely exposed to dispersants while cleaning up the 2010 Deepwater Horizon oil spill experienced a range of health symptoms including cough and wheeze and skin and eye irritation, according to scientists at the National Institutes of Health (NIH). The Pipeline and Hazardous Materials Safety Administration (PHMSA) is cracking down on smaller violations in the crude oil, petroleum, and hazardous liquid industries to combat a slow rise in the number of pipeline accidents. Natural source zone depletion (NSZD) is the new technical term for naturally occurring biodegradation processes that reduce petroleum, nonaqueous-phase liquids (NAPL) from the subsurface. The appeals court ruled that, while regrettable, the fact that the spill occurred does not mean that ExxonMobil violated pipeline integrity regulations for risk assessment.
Because of inherent complexities, understanding the characteristics of perforations in downhole environments is a significant challenge. Perforation-flow laboratories have been used to provide insight into cleanup and productivity mechanisms around perforation tunnels. Erosion caused by fine solid particles presents one of the greatest threats to oil and gas flow assurance, consequently affecting material selection and wall-thickness design.
Because of inherent complexities, understanding the characteristics of perforations in downhole environments is a significant challenge. Perforation-flow laboratories have been used to provide insight into cleanup and productivity mechanisms around perforation tunnels. Completion engineers feel pressure to maximize production per acre and minimize the downsides of fracturing in tight spaces. Terry Palisch, talks about promoting knowledge sharing as part of JPT’s tech director report. An advisor at Schlumberger discusses the company’s work in examining the effect of perforations on hydraulic fracture initiation.
Oil spill is considered as one of the biggest ecological disasters due to the scale of the impact it has, on the ecosystem being affected. Offshore oil spills have proven to be a global concern for marine ecosystem and appropriate measures for their control, prevention and removal of contaminants must be considered as top priority.
This paper entails a detailed study of the various available oil spill clean-up techniques and looks at its advantages and limitations. Further, a grading system for all these methods based on oil type, treatment volume, weather conditions, complexity, water turbulence, time required for results, their environmental impact, cost and efficiency is prepared.
In the case of a spill, oil dispersion behavior acts differently for different kind of fluids on sea water depending on their properties, with the effect of turbulence being one of the critical factors. This paper also focuses on the study of different behavior of crude oil and gasoline on sea water using a commercially available CFD (computational fluid dynamics) tool which utilizes more accurate and relevant mathematical formulations. A multiphase oil spill model has been developed to simulate dispersion of oil spill. A consistent Eulerian approach and Navier-Stokes equations is applied across the model, and the diffusion is employed to simulate oil dynamics in the water. The used Multiphase Oil Spill Model takes advantage of recent developments in the areas of CFD.
On the Vega gas condensate and oil field in the Norwegian North Sea, two high temperature, high pressure (HTHP) gas condensate wells on one subsea template in 370 m water depth were acid and scale inhibitor treated in order to improve productivity by acid scale removal and prevent future scaling. Significant amount of work was undertaken on design and qualification of the treatment fluids. In order to reduce operation time and increase efficiency, a novel one-time connection concept was utilized. During the operations, wells were kicked off after energizing with gas bullheaded from the neighbouring well. The treatment fluids were designed to reduce consequences for the host facility due to H2S generated during the operation - this required optimization after understanding of the H2S source as witnessed in prior treatments.
The new concept with one-time connection was successfully employed and allowed for three subsequent well treatments in a row, thus saving at least two days vessel operations time. The gas injection from the neighbouring well - the one not treated at the moment - allowed for an efficient start-up of the treated well without need for larger nitrogen injection which would have led to contamination and potentially to flaring due to off-spec gas. The introduction of a batch with pH neutralizer and H2S scavenger batch into the treatment design to be placed into the production pipeline reduced H2S liberation and production to the host facilities, thus limiting the operational stress on the platform. Productivity of well A1 showed an immediately significant increase after the operations, whereas productivity of well A2 required a longer clean-up than originally anticipated.
One method of sustaining and optimizing a well through its lifetime is underbalance perforating. When hydrostatic pressure inside the wellbore at the zone of interest is kept at less than the expected reservoir pressure, the damaged and crushed zones across the critical matrix at the reservoir that cause low permeability in the perforation tunnels will be immediately cleaned up as soon as communication to the reservoir is established upon perforating. In an operation offshore Malaysia, underbalance perforating was performed in injection wells, rather than producing wells, to optimize injection rates. The operation employed a fiber-optic firing head deployed on a fiber-optic coiled tubing (CT) real-time telemetry system.
The most common and effective method to achieve underbalance is displacing the well to a lighter fluid, less than the water gradient, prior to perforating. Subhydrostatic wells with low bottomhole reservoir pressure pose challenges to achieving the underbalance state. For these wells, well fluids must be removed via nitrogen displacement and the completion perforated with a nitrogen cushion. After underbalance is reached, the well is ideally ready to be perforated as it is, without introduction of additional fluids.
In the offshore Malaysia field, water injector wells had been perforated overbalance because the objective of the wells was injection and not production. However, the injection rate of these water injectors started to decline below the optimum design rate only after a short period, thus affecting the production rate of the neighboring oil and gas producers. Two pilot wells were designed to be perforated underbalance, achieving immediate cleanup after firing. The challenge was to perform an underbalance perforation in a low-pressure, depleted reservoir, using nitrogen as a displacement fluid. After this condition was fulfilled with a 500-psi differential, the well was to be perforated without any liquid introduction to activate the guns, which restricted the use of pressure- and ball-activated firing heads.
The fiber-optic-enabled firing head deployed on CT with real-time telemetry system is considered the most efficient intervention approach to overcome the challenges set. The new firing head will allow the perforating command to be given through an optical signal instantaneously at depth with no disturbance to the well fluid dynamics. This technique will also optimize an online rig operation where displacement, perforation, and nitrogen lift contingency can be performed in one CT run, hence reducing operating costs. Since the initial startup of the two pilot wells, the injection rates of the wells are at optimum, and the performance gained from the two wells has increased overall production in the field. Real-time underbalance perforating is thus seen as the way forward not only to enhance producing wells, but also to boost injectors as well, prolonging the life of an offshore oilfield.
Considering the important role that perforation laboratory testing can play in establishing field completion strategies, and thus ultimately well performance, efforts are currently underway to further strengthen the link between laboratory results and field well performance predictions. Some of these efforts focus on integrating advanced diagnostic and computational tools (namely computed tomography (CT), and pore-scale flow simulation) into the perforation testing workflow. This integration enables local variations in permeability and porosity to be identified and quantified, thus improving the interpretation of perforation laboratory results, and ultimately the translation of these results to the downhole environment.
CT techniques have been used for core analysis, characterization, and flow visualization since the early 1980s. By the early 1990s, these techniques were being applied to the investigation of laboratory-perforated cores to enhance the interpretation of tests conducted following API RP19B Section 2 or 4. This application has increased dramatically since 2012, following the installation of a CT scanning system on-site at a perforating laboratory facility. As a result, this non-destructive technique has become a preferred method to routinely characterize perforation tunnels and the surrounding rock, as well as to enable the repeated inspection of a perforated core at multiple steps throughout a test sequence designed to mimic field operations scenarios. Coinciding with this development has been the advancement and application of micro-CT technology to better understand pore-scale phenomena, both near and away from the perforation.
This paper introduces an integrated test program currently underway and summarizes key results from two experiments in which stressed rock targets were perforated under significantly different conditions. The first experiment involved perforating a moderate strength sandstone core under conditions that retained substantially all perforation damage, thus preserving the "crushed zone". Micro-CT analysis of different locations within the crushed zone region revealed significant compaction, with porosity reductions ranging from 10 to 50% below that of the native rock. Permeability at one of these selected locations was determined and found to be reduced by approximately 35% below the native rock value. The second experiment involved perforating a very high-strength sandstone core under conditions intended to produce full cleanup. CT and micro-CT analysis revealed fine fractures near the tunnel tip and confirmed the near-complete removal of the perforation damage, with only a very thin (less than 1 mm) compacted zone remaining at the tunnel wall. Although this region is interpreted to have very low permeability (as indicated by the near-zero connected porosity detectable at the resolution investigated), a fracture network combined with the shell’s minimal thickness suggests that this would provide a minimal impediment to inflow.
Ongoing work aims to expand these findings and capabilities. A main effort going forward centers on simulating core-scale perforation inflow, incorporating the localized rock property variations determined as described in this paper. Additional property variations away from the perforation (for example, natural heterogeneity and/or anisotropy that often exist in reservoir wellcore samples) will also be taken into account. Such localized variations, both near and away from the perforation, are generally not taken into account in typical Section 4 test programs. Consequently, this ongoing effort will ultimately strengthen the relevance of Section 4 results to the downhole environment.
Hydraulic fracturing stimulation is considered a successful development technique in tight gas reservoirs. However, these expensive operations sometime underperform due to ineffective fracture fluid (FF) clean-up. This paper concentrates on FF clean-up efficiency for a Multiple Fractured Horizontal Well (MFHW) completed in both homogeneous and naturally fractured (NF) tight gas reservoirs. The emphasis is on NF reservoirs that make up a large percentage of tight gas assets, as their clean-up efficiency has received little attention.
In this study, two numerical simulation models, i.e. a single-porosity single-permeability and a dual porosity-dual permeability model representing a homogeneous and a NF tight gas reservoir respectively, were used. Simulations were conducted on a MFHW with seven hydraulic fractures (HF). The process comprised of injection of FF, then a soaking time (ST) followed by production. The impact of various parameters which includes ST, FF viscosity, pressure drawdown and parameters pertinent to relative permeability and capillary pressure in matrix, hydraulic and natural fractures, were evaluated.
In addition, based on a newly proposed treatment process that generates in-situ pressure and thermal energy that breaks gel viscosity, the effect of resultant viscosity reduction and local pressure increase, for improving the clean-up efficiency was also assessed. In these simulations, and due to uncertainty in its value, NF permeability was varied over a wide range. For conclusive purposes, Gas Production Loss i.e. GPL (%) defined as the difference in total gas production between the completely clean and un-clean cases as a percentage of the clean case, after a specific production period was used. This paper prioritizes the impact of pertinent parameters and highlights the influence of thermochemicals on the clean-up efficiency thereby justifying its commercial practicality. For instance, it is shown that the presence of NFs results initially in higher GPL but then GPL reduces significantly. Reducing the FF viscosity improves clean-up significantly especially for the NF models as NFs are the main contributor to the gas and FF flow from the reservoir to surface via hydraulic fractures. The sometimes non- monotonic trend of GPL variations, depends on the specific combination of NFs’ permeability and FF viscosity which results in the certain fluid invasion profile and mobility in the system.
The paper emphasis is on the impact of thermochemicals and natural fractures on the cleanup up efficiency of hydraulic fracturing stimulations that should be optimized to reduce cost, thereby increasing the profit from these projects.