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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.
Al-Ismael, Menhal (Saudi Aramco) | Awotunde, Abeeb (King Fahd University of Petroleum & Minerals) | Al-Yousef, Hasan (King Fahd University of Petroleum & Minerals) | Al-Hashim, Hasan (King Fahd University of Petroleum & Minerals)
Reservoir characterstics and profitability are two important constraints in any field development. Net present value (NPV) is usually used to measure the cash flow profitability profile and determine associated financial risks. On the other hand, voidage replacement ratio (VRR) is used to measure the rate of change in reservoir energy. In recent studies, VRR was used as an additional objective in well placement optimization. Such studies proposed minimizing single value of VRR that represents the entire reservoir. However, such single VRR value may not detect unbalanced distribution of reservoir pressure. Severe alteration of voidage replacement distribution could occur in the reservoir that could not be represented accurately by a single value of VRR. Therefore, we propose a more efficient method to overcome disparate regional pressure changes in well placement optimization. This new method is based on optimization of NPV constrained to regional average pressure of the reservoir. Differential evolution algorithm was applied to find the optimum well locations that yield the maximum NPV constrained to regional pressure balance. The regional pressure balance was achieved by specifying a maximum allowable difference between any two regional pressures. We evaluated four scenarios of reservoir development. The first two scenarios involve the use of predefined well patterns. In these scenarios, the well locations were selected without any optimization. The third scenario involves the optimization of well placement without constraining it to any pressure balance. The fourth scenario involves optimization of well placement constrained to regional pressure balance. The results obtained indicate that we can minimize the difference of average pressure between regions while achieving high values of NPV. This helps to have a uniformly distributed reservoir pressure throughout the production life of the reservoir.
Enhanced oil recovery (EOR) techniques are very expensive processes especially in harsh reservoir environment such as high temperature, pressure and salinity as the applications of classical EOR techniques have been limited to certain reservoirs. This work is aimed to design a cost effective EOR technique utilizing Ethylenediaminetetraacetic acid (EDTA) chelating agent solutions prepared using undiluted seawater (57k ppm).
Chelating agents have been used in petroleum industry as matrix stimulation fluids because of their ability to dissolve calcite and chelate the interlayer cations of clay minerals especially (Fe+3 and Ca+2) and keep them in solution without any significant precipitation. Recently, coreflood tests of sandstone core samples using EDTA solutions revealed significant increase in oil recovery during the tertiary mode. This paper presents a new approach to optimize oil production and minimize the injection pressure needed to flood sandstone reservoirs by injecting chelating agent solutions prepared in seawater without dilution with moderate to high pH levels and optimized concentrations in a sequential form after conventional waterflooding starting with small concentration followed by higher concentrations. The main objective of this approach is to optimize the concentrations and pH of the EDTA chelating agent solutions prepared in undiluted seawater for better oil recovery and improved injectivity using sandstone core samples. Coreflood tests at 100°C were conducted using Gray Berea sandstone core samples.
Coreflood results showed incremental oil recovery of about 15% of OOIP when the samples were flooded by the 5wt% chelating agent solution. The pressure drop during the flooding sequence confirmed that there was no damage due to clays detachment and migration or calcite dissolution at the experiments conditions of pH higher than 9.75 and EDTA concentration of 5wt% or less in undiluted seawater for Gray Berea sandstone samples.
A cost effective EOR fluid system having optimum chelating agent concentrations and pH have been designed to function as surface chemistry agents for alteration of sandstone rock wettability to a more water-wet conditions, and hence, can be used as EOR fluids.
Handling excessive water production is one of the most common challenges in mature oil fields. The world produces almost five barrels of water with each barrel of oil. Cyclic Production Scheme (CPS) was applied as a first field trial in the world in one of mature oil fields in Saudi Aramco to maximize ultimate oil recovery, reduce water production and enhance reservoir pressure.
The results of a conceptual simulation model that was built to assess reservoir performance under the CPS are discussed. Sensitivity cases were carried out to identify the most influential reservoir parameters on CPS. This assessment is to support the understanding and engineering interpretation behind the performance of the CPS.
The CPS is an innovative concept to produce oil from mature fields. The scheme requires alternating shutting and flowing wells with high water cut over a predetermined period of time. CPS is not known globally in the oil industry yet.
Over the last decade, cyclic water injection has received great attention since many laboratory works, simulation studies and field tests have shown that it may lead to additional oil recovery, especially in mature oil fields. Excessive water production is one of the most common problems to be dealt with in mature fields1. The world produces 300-400 million barrels water per day (BWPD) for 75 million barrel of oil2. The world average oil recovery factor is estimated to be 35%. Additional recovery over this average dictates the application of novel technologies, economic viability, and in conjunction with effective reservoir management strategies. An estimated 30 giant fields, mostly categorized as mature fields, constitute half of the world oil reserves.
In this study, a conceptual simulation model is built to better evaluate the effects of the CPS on reservoir performance.
Although the CPS is a new concept as mentioned earlier, the cyclic term appeared in the literature since the late 1960s. All previous cyclic works were devoted mainly for water injection to improve oil recovery and optimize water injection as documented extensively in the literature over the past 40 years.