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Abstract Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). In this study, we present a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, we show that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements.
Mohsin, Adel (College of Science and Engineering, Hamad Bin Khalifa University) | Abd, Abdul Salam (College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad (College of Science and Engineering, Hamad Bin Khalifa University)
Abstract Condensate banking in natural gas reservoirs can hinder the productivity of production wells dramatically due to the multiphase flow behaviour around the wellbore. This phenomenon takes place when the reservoir pressure drops below the dew point pressure. In this work, we model this occurrence and investigate how the injection of CO2 can enhance the well productivity using novel discretization and linearization schemes such as mimetic finite difference and operator-based linearization from an in-house built compositional reservoir simulator. The injection of CO2 as an enhanced recovery technique is chosen to assess its value as a potential remedy to reduce carbon emissions associated with natural gas production. First, we model a base case with a single producer where we show the deposition of condensate banking around the well and the decline of pressure and production with time. In another case, we inject CO2 into the reservoir as an enhanced gas recovery mechanism. In both cases, we use fully tensor permeability and unstructured tetrahedral grids using mimetic finite difference (MFD) method. The results of the simulation show that the gas and condensate production rates drop after a certain production plateau, specifically the drop in the condensate rate by up to 46%. The introduction of a CO2 injector yields a positive impact on the productivity and pressure decline of the well, delaying the plateau by up to 1.5 years. It also improves the productivity index by above 35% on both the gas and condensate performance, thus reducing production rate loss on both gas and condensate by over 8% and the pressure, while in terms of pressure and drawdown, an improvement of 2.9 to 19.6% is observed per year.
In CO2 storage projects, CO2 usually enters the target reservoir at a lower temperature than that of the surrounding rock and its density is increased. The injection temperature affects how much CO2 can be stored. In this work we investigate the impact of heat exchange during CO2 injection into the Surat Basin, Australia, using integrated reservoir modelling. We evaluate the aquifer storage and sealing capacities, as well as pressure build up and CO2 plume migration.
Flow simulations of CO2 injection into the Precipice Sandstone were conducted with injection temperature from 40 to 80°C. The modelling domain consists of the reservoir sandstone, an overlying transition zone (muddy sandstone) and above it, the ultimate seal. The distribution of porosity, permeability and capillary pressure is heterogeneous. Heat exchange between rock and fluids was enabled in the commercial simulator to evaluate changes in fluid properties due to wellbore cooling. The initial temperature was set to 80°C. The injector’s wellbore pressure drop is modelled honouring a constant well head pressure of 15,000 kPa. The maximum allowed bottom-hole pressure is 90% of a thermally reduced fracturing pressure.
The viscosity of water and CO2 increases during cooling of the near wellbore zone; thus, pressure build up grows faster in the case of lower injection temperatures. Although the bottom-hole pressure becomes higher, injection rate is constrained by well head pressure. Heat exchange also increases the density and saturation of CO2 at the plume edge, which causes a sharper and faster advancing front. Higher pressure in the reservoir forces fluids to migrate to the transition zone, which also reduces its temperature. CO2 flows preferentially through the lowest capillary pressure channels and is able to permeate slightly into the transition zone. These physical conditions at the bottom of the well (lower temperature and higher pressure) lead to a denser CO2 plume and a greater mass is stored in the reservoir each year.
This work analyses non-isothermal injection of CO2 into an aquifer using integrated reservoir modelling. It illustrates how reservoir cooling may increase the rate of CO2 storage and slight migration to the transition zone.
Sabirov, Denis Galievich (Gazpromneft STC) | Demenev, Roman Aleksandrovich (Gazpromneft STC) | Isakov, Kirill Dmitrievich (Gazpromneft STC) | Ilyasov, Ilnur Rustamovich (Messoyakhaneftegaz) | Orlov, Alexander Gennadievich (Messoyakhaneftegaz) | Glushchenko, Nikolay Aleksandrovich (Messoyakhaneftegaz)
Abstract Most of the Russian oil fields consist of the complex reservoirs and it is required to apply secondary reservoir development methods, such as waterflooding, in order to increase reservoir development efficiency. However, for highly heterogeneous reservoir with viscous oil, "classical" waterflooding is not enough and there is a need to use enhanced oil recovery methods, one of which is polymer flooding. The prospects polymer solutions injection have been proved in different fields worldwide, including the East-Messoyakhskoye field at the PK1-3 reservoir with high-viscosity oil. At this field, polymer flooding pilots were carried out and taking into account the obtained field data, the geological and dynamic model were updated, which helped to improve the process physics understanding and evaluate the possibility of sweep efficiency increase during project implementation. This paper describes the challenges, difficulties, applied approaches, results and experience obtained in reservoir simulation of polymer flooding.
In case of brown fields and fields currently undergoing drilling, it is highly important to revise field geology to effectively design pressure support and further refine the existing pressure maintenance system if required. At the same time, the analysis of cross-well interference using Multiwell Retrospective Testing (MRT) is very useful for assessing its effectiveness, and is the main tool, that was used at one of the fields in Tatarstan Republic.
Conventionally to identify the geological structure and assess the reservoir connectivity it is required to use tools that could be quite costly, require expensive field operations and take up a lot of time. These tools include seismic surveys, paleotectonic analysis of the survey zone, tracer surveys and interference tests. Each of these methods comes with well-known disadvantages: weak seismic sensitivity to low-amplitude faults, poor resolution of tectonic analysis, long duration of tracer surveys and their low performance against man-made fractures and inconsistent extension in lateral anisotropy of the reservoir, huge production losses during interference tests due to receiving well shut-ins. In this regard, the MRT technology was chosen as the main tool for assessing pressure support at the brown field. This technology is fully fledged and is currently being implemented at a large-scale, having passed the testing stage on both synthetic and actual fields (
In accordance with the conducted surveys, the reservoir geology was refined, inefficient injectors in terms of pressure support was identified, and it was advised to redistribute the injection to balance it out that will ultimately lead to production increase.
Alzahabi, Ahmed (University of Texas Permian Basin) | Trindade, A. Alexandre (Texas Tech University) | Kamel, Ahmed (University of Texas Permian Basin) | Harouaka, Abdallah (University of Texas Permian Basin) | Baustian, Wade (Camino Natural Resources) | Campbell, Catherine (Camino Natural Resources)
One of the continuing puzzle pieces for all unconventional plays is drawdown (DD) technique for optimal Return on Investment (ROI). A solid approach to determine this valuable piece of information has yet to be found, as many operators are reluctant to reveal the production, pressure, and completion data required. Among multiple parameters, various completion and spacing parameters add to the complexity of the problem. This paper aims to determine which drawdown strategy leads to the highest return in the Anadarko Basin,, specifically evaluating the Woodford and Mayes formation. Several drawdown techniques were used within the Anadarko Basin in conjunction with different completion techniques. Private production and completion data were analyzed and combined with well log analysis in conjunction with data analytics tools. This case study explores a new strategy to drawdown producing wells within the Anadarko basin to achieve ultimate ROI. We perform data analytics utilizing analytics (scatterplot smoothing) to develop a relationship between two dependent variables Estimated Ultimate Recovery (EUR) and Initial Production (IP) for 180 days of Oil vs. drawdown. We present a model that evaluates horizontal well production based on drawdown parameters. Key data were estimated using reservoir and production parameters. The data led to determination of the most optimal drawdown technique for different reservoirs within the Anadarko Basin. This result may help professionals fully understand the Anadarko Basin. By use of these optimal parameters, we hope to completely understand the best way to drawdown wells when they are drilled simultaneously. Our findings and workflow within the Woodford and Mayes formations may be applied to various plays and formations across the unconventional play spectrum. Optimal drawdown techniques in unconventional reservoirs could add billions of dollars in revenue to a company's portfolio and increase rate of return dramatically, as well as offer a new understanding of the reservoirs in which we are dealing with.
Abstract This study aims to analyze and compare the influence of the diameter selection on the optimal gathering system position. Taking into account different well positions scenarios. Utilizing both manifold and trunk line layouts, this study will rank the results considering the oil production and costs of the subsea arrangement. The optimal position will be calculated through the usage of multiphase flow simulations and a genetic algorithm. The results will show that the relation between the flowline and trunk line diameter is critical for maximizing efficiency, and that the manifold's optimal position is greatly affected by certain changes in flowline diameter. Introduction Being able to plan the most efficient subsea layout in deep water environment is one of the most important parts in designing an offshore production system. Aside from a refined study about wellhead and platform positions, the key to maximize revenue is to determine the best way to arrange the subsea equipments such as manifolds and trunk lines, being aware of its installation costs, amount of associated flowline's extent and production capability. Adequately manipulating the quantity and type of subsea equipments will bring down the overall subsea layout cost as it reduces the number of individual risers and flowlines of each well. By gathering as many wells as possible into one single flowline to the production unit, it is possible not only reduce the cost associated with installed flowline length, but also reduce the total weight load on the platform, as fewer risers will be connected to it. Considering the space on the riser balcony is a limited parameter in the production unit, the reduction of the number of risers attached will also allow for more wells to be connected directly to the production unit. Both manifold and trunk lines are assets which offer a multitude of ways to interconnect wells in petroleum fields. These gathering systems are an arrangement of piping and/or valves designed to combine, distribute, control and often monitor fluid flow (Bai & Bai, 2010). As shown in (Fig. 1), manifolds converge the production from multiple wells at a unique point, and from there the oil flows along a single flowline to the host production unit (Leffler et al., 2011). Trunk lines, as seen on (Fig. 2), are typically major-long distance line united by headers, gather production into a single flowline from multiple wells at different points of its length until eventually flowing upwards to the host unit. (Sukumar, 2018). These connection points are commonly called headers.
Abstract In this paper, we analyze and simulate the production data before and after an extended shut-in period from a horizontal well completed in the Montney Formation. After flowback and early post-flowback production, the well was shut-in for 7 months due to facility completion. When the well was reopened, the hydrocarbon production rates increased significantly compared to the values before the shut-in. To investigate the reasons behind this enhancement, we simulated three-phase production rates and bottom-hole pressure using the actual reservoir geological model. To match the production data before the shut-in period, we had to account for the reduction in oil and gas relative permeabilities due to water blockage. This was done by using multipliers of interblock fluid-flow transmissibility near the matrix-fracture interface. We used these transmissibility multipliers as matching parameters, to achieve the match between measured and simulated production data. However, the best history match was achieved, when the values of transmissibility multipliers are increased by 6.5 times after the shut-in. This suggests a significant increase in oil and gas relative permeabilities due to reduction in water blockage near fracture-matrix interface during the extended shut-in period. Since the simulation model was not able to capture the imbibition process controlled by different driving forces, we used transmissibility multipliers to mimic this phenomenon and its corresponding effects on production rates. In addition, we performed sensitivity analyses to investigate the effects of shut-in on the well productivity and economic profitability in terms of net present value (NPV). The results show that for this well, a 6-month shut-in period is optimal for maximizing NPV and hydrocarbon production.
A CO 2 huff-n-puff pilot implemented in the Midland Basin demonstrated a significant oil rate improvement, but also witnessed an escalation in water-cut up to 0.3. A compositional model was established to consider the complex physics including cyclic stress changes, reopening of water-bearing layers, reopening of unpropped fractures and its resulting relative permeability shift. Our previously published work suggested that the reopening of unpropped fractures and its resulting relative permeability shift contributes most to the abnormal water cut surge after gas injection. In this study, we further proposed several operational constraints to manage such high water-cut occurrence after gas injection. The optimized simulation results suggested that around 1.5 times increase in recovery factor can be achieved after six CO 2 huff-n-puff cycles. Sensitivity analysis was subsequently conducted regarding parameters such as soaking time, injection time, and bottom-hole pressure. It was found that soaking time and bottom-hole pressure did not have much influence on cumulative oil production. Setting injection time as 150 days in each cycle can achieve the highest net present value. The primary objective of this study is aimed at optimizing techniques for conducting CO 2 huff and puff process to maximize oil production and minimize CO 2 emission.
Estimation of flowing bottom-hole pressure in multiphase flow is done through empirical correlations like Beggs and Brill or Gray correlation. These correlations were developed in time when computing power was limited and some were developed based on water-air mixtures, making them less accurate in real oil and gas production scenarios. Regardless, due to lack of other alternatives, general empirical correlations, like the ones mentioned previously, are widely used in the industry for estimating flowing bottom-hole pressure in multiphase flow.
Machine learning and Artificial Intelligence (AI) are emerging techniques in analyzing a large set of data to identify relations and patterns in multivariate problems. The method used in this paper – Quasi-Monte Carlo (Latin Hypercube sampling) – randomly selects input data to create empirical correlations between flowing parameters and bottom hole pressure. In this study, production data (oil, gas, water flow rates, and flowing wellhead pressure) from an oil well is used as input, and an algorithm based on Latin Hypercube sampling selects random variables from each of the parameters to generate several correlations. The correlation with the minimum error is chosen.
From the developed equation, the calculated flowing bottom hole pressure was within an average error of 5%. The advantage of this method is that it does not require any tubular information, such as tubing internal diameter, surface roughness, or tubing restrictions. In addition, the average reservoir pressure can be estimated from the constant of the model. Furthermore, the application of this method can be used to indirectly infer several fluids or rock properties.
This is a novel method to statistically estimate flowing bottom-hole pressure using only production data. This method can also be expanded to gain knowledge about other reservoir properties.