Bhardwaj, Charu (Cairn Oil & Gas, Vedanta Limited) | Ranjan, Vishal (Cairn Oil & Gas, Vedanta Limited) | Jetley, Shailendra Kumar (Cairn Oil & Gas, Vedanta Limited) | Tiwari, Shobhit (Cairn Oil & Gas, Vedanta Limited) | Ghosh, Anirban (Cairn Oil & Gas, Vedanta Limited) | Sharma, Swapnil (Cairn Oil & Gas, Vedanta Limited) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Limited) | Kumar, Abhishek (Cairn Oil & Gas, Vedanta Limited) | Beohar, Abhudai (Cairn Oil & Gas, Vedanta Limited) | Sharma, Sidharth (Cairn Oil & Gas, Vedanta Limited)
The Raageshwari Deep Gas (RDG) field, situated within Barmer Basin in the State of Rajasthan, India, was discovered in 2003. The field is a tight gas condensate reservoir, with excellent gas quality of approximately 80% methane, low CO2 and no H2S. Since the permeability (0.01 - 1 md) is low in this reservoir, hydraulic fracturing is required to get substantial recovery from the wells. The field has been under production since 2010. The development of this field has been carried out in three phases and more than 150 fracturing treatments have been pumped in this reservoir till date to achieve sustained economical production. This paper deals with the lessons learnt and changes implemented in choke design through various development phases of the field.
In the initial phase of field development, chokes with a low Flow Coefficient (Cv) were installed to meet the requirement of controlling the wells at low flow rates and high differential pressure. Later as the surface handling capacity increased, the chokes had to be de-bottlenecked, requiring additional Capex for new chokes. To avoid a similar scenario in the future, a comprehensive approach has been followed to envisage Cv requirement, considering well wise production profiles and surface handling capacities throughout the life of field. Since a single trim can't operate over the complete life-cycle of a well, trim interchangeability has been included in the choke design such that low and high Cv trims are interchangeable.
Pre-mature failures of trims were observed in initial phase and a root cause analysis was done to ascertain the reason. Based on the analysis, trim metallurgy has been changed from Tungsten Carbide to ASTM A276 Specific Stainless Steel Grade 440C. Trims with newly selected mettalurgy have been installed in the existing chokes.
The introduction of trim interchangeability has saved MMUSD 0.3 in the future Opex as the requirement of procuring altogether new chokes for late life period of wells is avoided. Initially failures in the trim bodies were observed as early as two months of commissioning but with the change in metallurgy zero failures have been observed with operational life of chokes being higher than four years. This has avoided significant downtime on wells and expenditure on regular trim changeovers.
Although Tungsten Carbide is one of the most common materials used for constructing trims world over, there could be specific cases where-in other metallurgy may add better value. The workflow followed in this paper will help select a suitable metallurgy and can impart a significant value to the industry.
Managing adequately pressure drawdown should be a key technical reservoir management driver due to its major impact on cash flow, acceleration and final recovery factor for operating hydraulically fracture shale gas condensate producers. Permeability should be regarded as a key dynamic property for ultra-low permeability shale reservoirs that influences shale hydrocarbon recovery. It is paramount to develop a pressure depletion plan that captures the pressure drawdown strategy and the changes in flow capacity associated to the interaction of the nano-Darcy rock and hydraulic fractures with stress dependent permeability effects.
Defining the adequate drawdown strategy would aid maximizing the economic recovery. Considering the variability of permeability with pressure drawdown should be part of the reservoir management lifecycle for unconventional shale reservoirs. This study focus on evaluating the impact of pressure drawdown strategy on initial rates and recovery for a Duvernay Gas condensate producer with an initial condensate yield of 100-150 stb/mmscf.
A sector compositional reservoir simulation model was built for a horizontal multistage hydraulically fracture Duvernay shale gas condensate producer. A full assessment of variability of permeability in the nano-Darcy rock and in the propped hydraulic fracture stages near the wellbore region was accomplished. Aggressive, moderate and conservative pressure drawdown strategies were evaluated, considering multiple operational pressure drawdown incremental ranges from 14.5 to 95 psia per day.
Results clearly indicate that implementing daily pressure drawdown increments of 22 to 29 psia per day would provide a similar recovery factor than imposing daily pressure drawdowns of 44 to 95 psia per day. However, there is a golden operating window opportunity to accelerate recovery by imposing maximum drawdown from the early days of production and bringing significant benefits of accelerating recovery with an associate increase in revenue but the benefits of this acceleration vanished in less than one year due to substantial changes in hydraulic fracture conductivity and also in the nano-Darcy rock permeability in the near wellbore region. The reduction of nano-Darcy permeability is a function of pressure, time and distance from the hydraulic fractures. According to our results, the best reservoir management practice for operating lean/medium Gas Condensate unconventional shale producers should be maximizing pressure drawdown at the early stage of the life cycle and deferring the installation of production string to maximize inflow-outflow.
Hydrocarbon-reservoir-performance forecasting is an integral component of the resource-development chain and is typically accomplished using reservoir modeling, by means of either numerical or analytical methods. Although complex numerical models provide rigorous means of capturing and predicting reservoir behavior, reservoir engineers also rely on simpler analytical models to analyze well performance and estimate reserves when uncertainties exist. Arps (1945) empirically demonstrated that certain reservoirs might decline according to simple, exponential, hyperbolic, or harmonic relationships; such behavior, however, does not extend to more-complex scenarios, such as multiphase-reservoir depletion. Because of this limitation, an important research area for many years has been to transform the equations governing flow through porous media in such a way as to express complex reservoir performance in terms of closed analytical forms. In this work, we demonstrate that rigorous compositional analysis can be coupled with analytical well-performance estimations for reservoirs with complex fluid systems, and that the molar decline of individual hydrocarbon-fluid fractions can be expressed in terms of rescaled exponential equations for well-performance analysis. This work demonstrates that, by the introduction of a new partial-pseudopressure variable, it is possible to predict the decline behavior of individual fluid constituents of a variety of gas/condensate-reservoir systems characterized by widely varying richness and complex multiphase-flow scenarios. A new four-region-flow model is proposed and validated to implement gas/condensate-deliverability calculations at late times during variable-bottomhole-pressure (BHP) production. Five case studies are presented to support each of the model capabilities stated previously and to validate the use of liquid-analog rescaled exponentials for the prediction of production-decline behavior for each of the hydrocarbon species.
Hassan, Amjed (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Majed, Abdulaziz (King Fahd University of Petroleum & Minerals) | Al-Nakhli, Ayman (Saudi Aramco) | BaTaweel, Mohammed (Saudi Aramco) | Elktatany, Salaheldin (King Fahd University of Petroleum & Minerals)
Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution for condensate removal in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. Also, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal.
In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in-situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature, or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 hrs. of mixing and injection. Also, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used.
The results of this study showed that, the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure from the thermochemical reaction. These micro-fractures reduced the capillary forces that hold the condensate and enhanced its relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.
Jie, Zhang (CNPC Engineering technology R&D company limited) | Xu, Xianguang (CNPC Engineering technology R&D company limited) | Wang, Lihui (CNPC Engineering technology R&D company limited) | Li, long (CNPC Engineering technology R&D company limited) | Zhang, Die (CNPC Engineering technology R&D company limited) | Zhao, Zhiliang (CNPC Engineering technology R&D company limited) | Wang, Shuangwei (CNPC Engineering technology R&D company limited)
Severe formation damage is induced by the invasion of working fluid and the subsequent water blocking. Surface modification by surfactant adsorption can change the wettability of the rock surface to enhance the removal efficiency of reservoir fluid and reduce the water blockage damage. Therefore, surfactant shows a good potential applicant in condense reservoir. In the current paper, an oligomeric silicone surfactant (OSSF) containing sulfonic acid groups is synthesized to improve the water flowback effect.
The critical micelle concentration (CMC) is determined by equilibrium surface tension. Micelle can be formed above the CMC and its size and distribution increase with the concentration. At the same time, the surface tension increases with the aging temperature but decreases with the adding of inorganic salt. The OSSF adsorption through solid-liquid surface can change the surface chemical composition and transfer the wettability of reservoir from water-wet to gas-wet by decreasing the surface energy. Increasing temperature leads to the change in the adsorption isotherm from Langmuir type (L-type) to "double plateau" type (LS- type). Quantum chemistry study shows that the adsorbed layer of OSSF can reduce the adhesive force of CH4 and H2O on the pore surface of cores. The OSSF can also decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).
It is found that the surface tension of OSSF increases with aging temperature but decreases with the adding of inorganic salts.The OSSF has positive effect on wettability reversal to water-wet reservoir by adsorption on solid-liquid interface. The results indicate OSSF adsorption layer can change surface chemical composition and exhibit lower interface energy than that of the cores. The presence of NaCl can decrease foaming volume and improve foam stability of OSSF. At the same time, OSSF can decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).
Ali, Hamza (Schlumberger) | Shah, Abdur Rahman (Schlumberger) | Akram, Agha Hassan (Schlumberger) | Khan, Waqar Ali (Schlumberger) | Siddiqui, Fareed Iqbal (Pakistan Petroleum Limited) | Waheed, Abdul (Pakistan Petroleum Limited) | Ahmed, Faizan (Pakistan Petroleum Limited)
A recent study addressed the modelling challenges of Alpha* gas condensate field. Alpha gas condensate field has a gas in-place of about 1 TCF, and both condensate and black oil production in addition. The field has been producing from two reservoirs SI and DI, for the past 26 years. Alpha field is subdivided into two segments called the Central Area and the Northern Area which are separated by a fault as shown in Figure 2. * Not its real name. One of the most unusual features of Alpha field are the'phase switch wells'.
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.
Gas condensate reservoirs are a major player in the oil and gas industry. Proper understanding of reservoir fluid composition and their spatial distribution helps define our resource base and forecast field production profile. In a gas accumulation with substantial vertical span, a composition gradient is expected, where heavier molecules gravitate towards the bottom end and lighter components' concentration increases towards the top of the column. However, in the literature some investigators have reported both condensate content and heavy hydrocarbon components decrease with increasing depth and temperature. Their observations appear to be contradicting the expected gravity driven compositional gradient as per thermodynamic equilibrium.
In this paper, we have done an integrated areal and vertical composition trend analysis of some gas condensate reservoirs across a big area i.e. a three-dimensional trend analysis. Field wide areal and vertical reservoir anhydrite content has been mapped. The areal composition gradient that defies expected gravity driven composition gradient, while honoring vertical thermodynamic equilibrium has been reconciled. Post depositional fluid/rock thermochemical reaction and low areal diffusivity has resulted in this areal variation. In-situ H2S generation has been enhanced where reservoir deepens and temperature increases, thus overcoming the activation energy hump. H2S concentration increase has happened at the expense of the hydrocarbon concentration as per the thermochemical reaction stoichiometry. It was found that the vertical compositional gradient is consistent with thermodynamic equilibrium calculations. Some observed trend anomalies have been explained using rock composition and geological information.
Thus, a three dimensional compositional gradient was deciphered for reservoirs with such behavior. The aim of this study has been to provide a better quality forecast for reserves, rate, recovery and composition mix for gas condensate fields.
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.
By racking up exploration agreements in the United Arab Emirates, Oman, and Bahrain, Eni took a big step forward in its pledge to tap into the Middle East’s vast swaths of highly prospective oil and gas acreage. Three onshore fields in the Emirate of Sharjah, United Arab Emirates, have more than 30 years of production history from more than 50 gas-condensate wells. For the next several years, supplies of crude will depend on several macro factors. Some are easier to forecast than others. The French major will become operator of the Ruwais Diyab concession, and ADNOC says additional companies are lining up to partner on the emirate’s other unconventional areas.