Condensate blockage presents a serious production problem due to loss of gas productivity. Several methods have been proposed to resolve condensate blockage to restore the well productivity, most commonly used technique is hydraulic fracturing. Although, it is most commonly used, it is not always feasible and favorable due to its inclusion of costly chemicals such as surfactants, which could also be as hazardous material. Our objective in the current study, is replacing such surfactants with natural green surfactants which are more economical and environmentally friendly.
Interfacial tension and contact angle experiments were carried out to examine the efficiency of two different natural green surfactants in comparison to two commonly used chemical surfactants in fracturing fluids. The results revealed that natural green surfactant is efficient in reducing the interfacial tension by 74.1% compared to 94.8% when using alcohol-based surfactants. Moreover, the natural green surfactant showed stronger effect in altering the surface wettability in sandstone formations towards strongly water-wet with a contact angle reduction of 61% compared to 32% in the case of alcohol-based surfactants.
Based on the concentration used here, the natural green surfactants are more cost-effective, a product cost reduction of more than 50% can be obtained. Being efficient in reducing the interfacial tension, altering the surface wettability towards stronger water-wet, abundant in nature, environmentally friendly, and, cheaper cost, this new proposed natural surfactant can replace the currently used chemical surfactants for condensate bloackage.
Al-Garadi, Karem (King Fahd University of Petroleum and Minerals) | Aldughaither, Abdulaziz (King Fahd University of Petroleum and Minerals) | Ba alawi, Mustafa (King Fahd University of Petroleum and Minerals) | Al-Hashim, Hasan (King Fahd University of Petroleum and Minerals) | Sibaweihi, Najmudeen (King Fahd University of Petroleum and Minerals) | Said, Mohamed (King Fahd University of Petroleum and Minerals)
Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells.
In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity.
The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.
Tariq, Zeeshan (King Fahd University of Petroleum & Minerals) | Al-Hashim, Hasan S. (King Fahd University of Petroleum & Minerals) | Sadeed, Ahmed (King Fahd University of Petroleum & Minerals) | Janjua, Aneeq Nasir (King Fahd University of Petroleum & Minerals)
When the pressure falls below the dew point in a condensate reservoir, condensate banking starts build up adjacent to the wellbore, the relative permeability of gas closes to the wellbore badly affected, ultimately causes the reduction in the well productivity index. In these cases, the influence of condensate blockage can be abridged by enhancing the inflow area and attaining linear flow rather than radial flow in the wellbore proximity. These characteristics can only be accomplished by conducting hydraulic fracturing job.
However, the performance of hydraulic fracturing treatment is highly dependent on the operational parameters. Estimation of optimal operational parameters of hydraulic fracturing is typically a difficult job for reservoir engineers. Enhancing the fracture half-length improves the well productivity but this scenario is misleading sometime. Fracture face skin is always associated with the fracture length that may induce additional pressure drop surrounding the fracture and can cause the gas condensate buildup. This happen because as the length of the fracture increases the damage surrounds the fracture cause by permeability impairment also increases, so there must be an optimum fracture length above which increasing the length of fracture is no more efficacious.
This research work presents a new methodology to quantify the amount of fracture face skin associated with the length of the fracture and determine optimum parameter for hydraulic fracturing in a gas condensate reservoir. To achieve the objective of this study a gas condensate simulation model has been created and the parameters associated with the hydraulic fracturing has been deeply investigated, particle swarm optimization has been used as an optimization technique to optimize the parameters that has been investigated.
After optimizing the parameters, the new approach has been proposed that suggests the optimum fracture parameters. This new approach is highly promising and can serve as very handy tool for reservoir engineers to determine the optimum operational hydraulic fracturing treatment parameters for a gas condensate reservoir.
The development of reservoirs that are not in hydrostatic equilibrium or that have suffered deviations from primary drainage over geological time requires appropriate challenges to standard assumptions in order to optimize the field's full potential. Such circumstances are more frequent than usually acknowledged since the Earth is not static, structures get buried or change with tectonic activity and fluids rearrange themselves to achieve a state of minimum potential energy. The focus of this paper is three fold: a) highlight geological processes that may affect fluid distribution and pressure regime in a reservoir; b) provide a template workflow and diagnostic tools for identification of alternative fluid-fill cycle and equilibrium state scenarios; c) illustrate through actual field examples the relevance of recognising tectonic imprint on fluid distribution, in particular for reservoirs with low permeability, oil wettability or low porosity.
Gas-condensate wells often experience a significant decrease in productivity once the flowing bottom-hole pressure drops below the dew-point pressure due to the dropout of condensate in the near-wellbore region. However, there is still a lack of understanding how composition changes in the condensate bank affect well deliverability and how to mitigate the effects.
This study addressed the recovery problem of gas-condensate reservoirs with the focus on composition variation. Full compositional simulations were conducted to investigate variations of composition and condensate saturation in the reservoirs. Different producing strategies were modeled to obtain producing sequences with enhanced recovery. Effects of mitigation techniques such as hydraulic fracturing and gas injection on the composition and recovery of gas-condensate reservoirs were also investigated. Furthermore, parameters governing gas injection in a gas-condensate reservoir were adjusted using a mathematical optimization algorithm to obtain the optimal recovery.
The study showed that composition varies significantly during depletion. Different producing strategies may impact the composition configuration and the amount of the condensate dropout in the reservoir. By taking into account the new understanding of how composition changes, the composition of the liquid dropout can be “controlled” by the production strategy and hence the recovery from gas-condensate reservoirs can be improved. The recovery of gas-condensate reservoirs can also be improved by hydraulic fracturing and gas injection due to changes in composition and saturation created by these mitigation techniques. Results from solving the mathematical optimization problem for methane injection demonstrated that optimal results are not always obtained with maximum gas injection rates. The same approach can also be applied to real producing reservoirs, by substituting the reservoir configuration in the numerical simulation with the real models.
Gas-condensate reservoirs are encountered frequently as exploration is now targeted at greater depth and hence higher pressure and temperature. The higher temperature and pressure lead to a higher degree of degradation of complex organic molecules. As a result, the deeper the burial of an organic material, the higher tendency the organic material will be converted to gas or gas condensate. Gas condensate usually consists mainly of methane and other light hydrocarbons with a small portion of heavier components. Gas-condensate reservoirs are typically in the gaseous state at initial reservoir conditions in which the reservoir pressure is above the dew-point pressure of the in situ fluid.
Significant reduction in well productivity of gas/condensate reservoirs occurs because of reduced gas mobility caused by the presence of condensate/water liquid phases around the wellbore.
There are certain fluorinated wettability modifiers that are capable of delivering a good level of oil and water repellency to the rock surface, making it intermediate gas-wet and alleviating such liquid blockages. The main objective of this experimental work has been to evaluate the performance of such chemicals for wettability alteration of carbonate rocks, which have received much less attention in comparison to sandstone rocks. Screening tests, including contact-angle measurements, unsteady-state-flow tests, and compatibility tests with brine, were performed by use of mainly anionic and nonionic fluorosurfactants.
Results demonstrated that on positively charged carbonate surfaces, the anionic chemicals were sufficiently effective to repel the liquid phase, whereas the nonionic chemicals showed an excellent stability in brine media. A new approach of combining anionic and nonionic chemical agents was proposed to benefit from these two positive features of an integrated chemical solution. A number of low- and high-permeability carbonate-core samples were successfully treated by use of chemicals selected through screening tests. Optimization of the solution composition and its filtration before injecting it into the core proved very effective in reducing/eliminating the risk of possible permeability damage because of deposition of large chemical aggregates on the rock surface. The chemical solution optimized in this study can be considered as a potential wettability modifier for mitigating the negative impact of condensate/water banking in carbonate gas/condensate reservoirs.
There is strong focus in the petroleum industry to drill safe infill target wells in producing hydrocarbon reservoirs. The so called operational window is strongly controlled by the rock mechanical processes in the formation being drilled. High pressure depletion and cooling effects contributes strongly to closing of the operational window. This is especially important in HPHT and similar fields with high depletion. For reservoirs where pressure depletion is the primary recovery mechanism, stress reduction is strongly controlled by pore pressure change. Other fields may employ water or gas injection for secondary recovery to supplement the energy drive of the reservoir; in such cases thermal stress changes are important to consider for upcoming drilling campaigns nearby existing gas/water injectors. Several examples from the industry have shown that the injection of cold fluids could have a significant effect on the stress inside a reservoir; evidence of losses close to injectors have previously been presented . The Åsgard Fields, Smørbukk and Smørbukk South are mature light oil and gas condensate fields located on the Halten Terrace offshore Mid-Norway. The main hydrocarbon accumulations are found in sandstones of Lower and Middle Jurassic age. Figure 1 shows the location of the Smørbukk and Smørbukk South fields on the NCS.
The Åsgard field was started up in 1999 and comprises the Smørbukk oil and Midgard gas assets. Midgard is developed with three subsea templates located approximately 45 km (31 miles) from the Åsgard field centre. Additionally, the gas field Mikkel located nearly 40 km (25 miles) further away is tied back to Midgard. To extend the life time of the Åsgard Field and achieve Increased Gas Recovery (IGR), boosting of well stream is necessary. Since 2005 Statoil has matured two concepts in parallel, a compressor platform and a subsea compressor facility. In October 2010 it was decided to go forward with the subsea facility. The Åsgard Subsea Compression (ÅSC) project is now building the world's first Subsea Compression Station (SCSt). ÅSC will be ready for operation in 2015 and secure production of 282 MMboes from the Åsgard field up to 2029.
The ÅSC SCSt will include two individual compressor train installed in a shared template with a total weight of 5100 tonnes, a footprint of more than 3300 m2, and height around 26 meters. The project includes novel technology especially related to gas compressors and subsea power distribution.
To mature the concept, a comprehensive Technology Qualification Program (TQP) was initiated in 2007 covering activities related to the following main building blocks: Process modules (coolers, scrubber, pump and compressor) Power system (long step out with topside Variable Speed Drive (VSD), transformers, HV swivel, connection system, umbilical / power cables) Control system (process, AMB and anti-surge) in addition to Hot-tap, remotely installed retrofit tee on the Midgard pipeline
Process modules (coolers, scrubber, pump and compressor)
Power system (long step out with topside Variable Speed Drive (VSD), transformers, HV swivel, connection system, umbilical / power cables)
Control system (process, AMB and anti-surge)
in addition to Hot-tap, remotely installed retrofit tee on the Midgard pipeline
The total qualification program included nearly 50 activities. Attention was given to define the TQ's in terms of gap analysis and failure modes, to ensure that the acceptance criteria reflected the necessary gathering of evidence to proof the equipment fit for service. The qualification has been done in collaboration with a series of vendors and research institutes. A large scale laboratory facility has been built at Statoil's R&D centre K-lab at Kårstø for testing gas compressors and long step-out power systems. The results from this work have been of crucial importance in maturing the subsea compression concept to the necessary level.
With gas production from gas condensate reservoirs, the flowing bottomhole pressure of the production well decreases. When the flowing bottomhole pressure becomes less than the dew point pressure, condensate accumulates near the wellbore area and forms a condensate bank. This results in loss of productivity of both gas and condensate. This becomes more serious in intermediate permeability gas-condensate reservoirs where the condensate bank reduces both the gas permeability and the well productivity.
Several techniques have been used to mitigate this problem. These methods include: gas cycling, drilling horizontal wells, hydraulic fracturing, injection of super critical CO2, use of solvents and the use of wettability alteration chemicals. Gas cycling aims to keep the pressure of the reservoir above the dew point pressure to reduce the condensation phenomena. The limited volumes of gas that can be recycled in the reservoir can hinder the application of this method. In order for an ideal recycle, gas volume injected into the reservoir will be larger than the total gas that can be produced from such a reservoir. Other approaches are drilling horizontal wells and hydraulic fracturing where the pressure drop around the wellbore area is lowered to allow for a longer production time with only single phase gas flow to the wellbore. These approaches are costly as they require drilling rigs. Another technique is the use of solvents which shows good treatment outcomes, but the durability is a questionable issue in these treatments. Moreover, wettability alteration needs to be approached very carefully as to not cause permanent damages to the reservoir. It was reported in many studies the use of fluorinated polymers and surfactants dissolved in alcohol-based solvents for wettability alterations treatments.
Each method has its own advantages and disadvantages, and can be applied under certain conditions. The paper presents all of these methods along with their advantages and disadvantages, besides description of some of their field applications and case studies.
One of the challenges in slickwater fracturing of tight sand gas reservoirs is post-treatment fluid recovery. More than 60% of the injected fluid remains in the critical near wellbore area and has a significant negative impact on the relative permeability to gas and well productivity. The trapped water could be due to capillary forces around the vicinity of the fractured formation. For strongly water-wet tight gas reservoirs, capillary forces promote the retention of injected fluids in pore spaces.
Commonly available surfactants are added to slickwater to reduce surface tension between the treating fluids and gas. The problem with surfactants is that upon exposure to the formation, they adsorb on the surface of the rock.
The addition of microemulsion to the fracturing fluid can result in lowering the pressure needed to displace injected fluids and/or condensate from low permeability core samples. This alteration of the fracturing fluid effectively lowers the capillary forces in low permeability reservoirs. This will result in removal of water and condensate blocks, the mitigation of phase trapping, and therefore an increase in permeability to gas.
This paper examines the effectiveness of microemulsions in the improvement of fracturing fluid recovery. Coreflood runs using 20 in. Bandera sandstone cores with residual condensate and water showed that the percentage of permeability regained due to treatment with microemulsion solutions was up to 150% depending on type of microemulsion.
An environment-friendly microemulsion formulated with a blend of a novel anionic surfactant, nonionic surfactant, short chain alcohol and water showed very good results in lowering interfacial tension between water and oil, when compared with competitive technologies. The performance of this microemulsion was excellent in high salinity fluid as well as low salinity fluid. It was excellent for solubilizing liquid condensates which can be found in wet gas wells. Contact angle of 63.45 degrees makes this microemulsion an optimal solution for cleanup of the near wellbore area. The resulting capillary pressure for a frac fluid treated with 0.25 wt% of this chemical in 2 wt% KCl is nearly 300 times lower than untreated fluid and 30 times lower than a fluid treated with competitive technologies.
Condensate-banking has become an important source of damage and reducing the well productivity. The effective permeability to gas reduces dramatically as a result of accumulated condensate near the wellbore and subsequently decreases the productivity of the well.
In gas reservoirs, the use of water-based fluid creates fluid retention problems and becomes more pronounced, as the combination introduces an additional phase to the reservoir, including an additional reduction in the effective permeability to the gas phase (Franco et al. 2013). Large quantities of fluid that has been trapped in the near wellbore area in the reservoir and in the case of fracturing, the fluid that have been trapped in the area surrounding the fracture and within the fracture itself, have detrimental effects on the relative permeability, the effective flow area, and effective fracture length, and impairs well productivity (Penny et al. 2005).