Water Content of Natural Gas in Equilibruim with Water

A new model for predicting water content of natural gas in equilibrium with water is obtained. This formula is a function of pressure and temperature and is applied within a wide range of temperatures and pressures. This new formula shows good data fit, with an average absolute error of 4.2 for 164 data points.     

Empirical Statistical Correlation for Estimating Solubility of Natural Gas in Crude Oil

Abstract

A formula for natural gas solubility in crude oil is developed. The correlation is function of pressure and temperature. Good results are obtained with average absolute percentage error 4.4% for 27 data points. This formula is valid for pressure of 4,900 psi and temperature range 188°F–256°F.     

Estimation of Hydrate Inhibitor Loss in Hydrocarbon Liquid Phase

Abstract

The amount of hydrate inhibitor to be injected in the gas processing and transmission system to avoid hydrate formation not only must be sufficient to prevent freezing of the inhibitor in the water phase but also must be sufficient to provide for the equilibrium vapor phase content of the inhibitor and the loss of the inhibitor in any liquid hydrocarbon. In this article, a new numerical algorithm is developed for estimation of loss of methanol in paraffinic hydrocarbons at various temperatures and methanol concentrations in the water phase The predicted values showed good agreement with the reported data. The solubility of methanol in paraffin hydrocarbons is calculated for temperatures in the range of 240° to 320°K and methanol concentrations up to 70% in the water phase, where the average absolute deviation is around 4%.     

Application of Abrasive Water Jet Perforation Assisting Fracturing

Abstract

This article presents a new technology of abrasive water jet perforation assisting fracturing on Well Zheng 408-8, Bin Nan Production Plant, Shengli Oilfield. First, the balsting tool, with 9 nozzles, was lowered down to the payzone and perforated 90 tunnels with abrasive water jet after being moved upward 9 times. Then the fracture work was conducted and 18 m³ sands were squeezed into the formations. After that the well production reached 11.6 t/d liquid and 8.7 t/d oil, respectively, and this continued for 9 months. But before the job, nothing was produced from this well.     

用混合物电导率公式改进双水模型的公式

双水模型把泥质砂岩的导电性看成是孔隙中粘土附近的粘土水和距粘土表面较远的自由水2种导电成份的并联结果.但是,在分析混合物的导电性时应考虑导电成份结构的影响,不宜只按并联或串联处理;泥质砂岩的导电性应是孔隙中的粘土水和自由水2种导电成份按其结构特性的混合联结(称为"混联")的结果.应用由2种导体成份组成的整体各向同性混合物电导率公式导出了双水混联模型的等效地层水电导率新公式.用新、旧公式计算的泥质砂岩电导率与实验数据的对比表明新公式更为准确,建议在测井解释中应用.     

Analytical Modeling of Gas Diffusivity Into Oil Through a Film of Water

Abstract

The authors aimed to determine diffusion coefficient of gas in oil when there is a water-blocking film between them. Dealing with this purpose, a new technique based on analytical modeling was developed to measure the diffusivity and solubility of gas into oil and water. The system that was described is solved analytically and numerically. The result of analytical solution is presented as different type curves, which are very simple to use. To generate data, a numerical scheme was employed. The determination of gas diffusivity and solubility emerged from matching concentration data with the type curves.     

Recovery Improvement Using Water and Gas Injection Scenarios

Abstract

Water and miscible gas injection scenarios are considered in an Iranian oil reservoir for the purpose of recovery improvement. Firstly reservoir fluid modeling and modeling of a slim tube test were performed. Then, water alternating gas (WAG) injection was evaluated by optimizing the WAG half cycle and WAG ratio. Alternatively, hybrid WAG and separate injection of water and gas in the top and bottom of the reservoir were also investigated. The numerical simulation results showed that the optimum WAG, with half cycle of 1.5 years and WAG ratio of one, gave the highest recovery factor. Moreover, economic evaluation of these scenarios indicated that WAG had the highest net present value and was the most interesting scenario for improving the recoveries.     

A New Method to Predict Water Breakthrough Time in an Edge Water Condensate Gas Reservoir Considering Retrograde Condensation

During the development of gas condensate reservoirs, condensate oil is separated as reservoir pressure drops to the dew point pressure. The prediction for water breakthrough time, the impact of precipitation of condensate oil, is usually ignored, which results in significant difference between prediction and realistic results. In order to better develop edge water condensate gas reservoirs and accurately predict the water breakthrough time, impact from condensate oil should be considered. Therefore, a new prediction formula of water breakthrough time is derived based on fluid flow in porous media considering impact of anti-condensate. A case study demonstrates that it is necessary to consider impact of condensate oil when predicting water breakthrough time. The new predicting formula provides theoretical basis for further research on edge water displacement mechanism as well as significant guidance for management of edge water gas condensate reservoirs.     

Generalized Formula for Compressibility Factor Z

Abstract

A new formula has been developed to permit calculation of the compressibility factor Z (compression factor) as a function of reduced temperature T _R and reduced pressure P _R. The formula offers flexibility for estimating compression factor for a wide range of reduced temperatures (T _R = 1–5) and reduced pressures (P _R = 0.5–6.5). This correlation provides an accurate and computationally reliable prediction of the compressibility factor Z with an average absolute error of 4.9% for 180 data points.     

On Estimating the Water Content of CO2 in Equilibrium With Formation Brine

Abstract

Water content of carbon dioxide (CO₂) is an important parameter in engineering applications, such as CO₂ storage in deep saline aquifers and enhanced oil recovery processes. A large number of experimental data have been reported on solubility of CO₂ in brine. However, experimental data on water content of CO₂ in equilibrium with formation brine are not reported in the literature. Water content of natural gas is traditionally calculated by general water content charts; however, these charts are not available for CO₂ in equilibrium with formation brine. Using an accurate fugacity and activity model available in the literature, the authors developed an efficient and simple procedure to estimate the water content of CO₂ in equilibrium with formation brine. To validate the developed procedure, the predicted CO₂-rich phase water content is compared with the reported experimental data in the literature and other predictive models for CO₂-water system. A CO₂ water content chart is presented that can be simply used to predict the water content of CO₂ in equilibrium with formation brine. The procedure presented may be used for generating necessary input data for flow simulation of CO₂ storage in deep saline aquifers.     

The Modeling and Simulation of the IWAG Process in Petroleum Reservoirs

Abstract

Application of an immiscible water alternating gas (IWAG) method in enhanced oil recovery process was investigated in this article. A black oil model was employed to reach the final equations required for estimation of pressure and saturation domains. The governing equations were discretized using a finite volume method. An implicit pressure–explicit saturation formula was employed to solve the equations. The system equations were solved and related codes were written to simulate the process. Simulation results confirm a higher oil recovery in the IWAG technique when compared to waterflooding and immiscible gas injection processes.     

Study and Application of In-depth Water Control Technology for Production Wells

Abstract

In view of low oil increment and short valid period of conventional water shutoff for production well, the authors propose and develop a new in-depth water control technology for production well. The different-strength (from weak to strong) water shutoff agents are separately injected into a remote zone, transition zone, and near-wellbore zone in this technology, which can achieve the aim of in-depth water control, extending the valid period of water control, increasing oil production, and decreasing water cut. Physical and visual simulation experiments show that there is optimized displacement of 3:10 between production well and injection well for the water shutoff agent with the most oil recovery. Field tests in Jidong, Shengtuo, and Weizhou 11-4 oilfields also show that the in-depth water control technology is a reliable, feasible technology and worthy to be widely applied.     

Characterization of the Pliocene Gas Reservoir Aquifers for Predicting Subsidence on the Ravenna Coast

Abstract

The Pliocene reservoirs of the North Adriatic have produced gas since 1972. Several studies using reservoir and geomechanical models have been undertaken to quantify the surface land subsidence that may be attributed to pressure depletion resulting from gas production. Subsidence may continue after production ceases, as water influx repressures the depleted gas reservoirs, reduces the aquifer pressure, and causes the subsidence bowl to expand. Therefore, characterization of the Pliocene aquifers and water influx functions is important for long-term prediction of subsidence. An aquifer model was developed by integrating geological/geophysical interpretations, petrophysical data, and pressure/production data to describe the limited water influx observed in these reservoirs. The mechanism restricting water influx in the Pliocene gas reservoirs was found to be a combination of low effective permeability to water in the presence of clays and trapped gas saturation. The final aquifer model, which was validated with field pressure data, was used to predict long-term pressure drop in the aquifer for subsidence predictions.     

Modeling of Shear Stress and Shear Strain Rate of Oil in Water Emulsions

Abstract

A simple model has been developed to predict shear stress as a function of shear rate and oil concentration. The model is based on the available experimental work that hasbeen done on the rheology of oil in water emulsions. The model predictions agree well with experimental data for the oil range concentration 0–70%.     

Prediction of Diffusion Coefficients for Binary Gas System

Abstract

A new formula has been developed to estimate diffusion coefficients for a binary system for some gases dependent on temperature, pressure, molecular weight, and a Pitzer acentric factor in a different range of temperatures. In this work, an introduction of the available observed data develops a new correlation for the effect of these parameters on the prediction of diffusion coefficients.     

The Prediction of Calcium Carbonate and Calcium Sulfate Scale Formation in Iranian Oilfields at Different Mixing Ratios of Injection Water with Formation Water

Abstract

This article presents the prediction of calcium carbonate and calcium sulfate scale formation by water injection in oilfields at different mixing injection water-to-formation water ratios. The experimentally measured chemical analyses of formation water and injection water were input to the OLI ScaleChem model to determine the tendency of scale formation. The scaling tendency of CaCO₃ and CaSO₄ at reservoir temperatures and pressures is presented. This model has been applied to investigate the potential of calcium carbonate and calcium sulfate scale precipitation in Iranian oilfields in onshore and offshore fields as a method of secondary recovery or reservoir pressure maintenance.     

Simple Correlation Accurately Predicts Densities of Glycol Solutions

Abstract

A simple-to-use correlation is developed to accurately predict the density of the most commonly used glycol solutions as a function of temperature and glycol wt% in water. The proposed correlation has very good agreement with the reported experimental data. The average absolute difference between the observed values and calculated results is 0.941 kg/m³, which is negligible compared to the actual density of aqueous glycols.     

Effect of Molecular Weight on Thermal Conductivity of Gases

Abstract

A new formula has been developed to estimate thermal conductivity of hydrocarbon gases dependent on molecular weight of the range 20–100 and under temperatures ranging between 0 and 400°F. In this work an introduction of the available observed data develops a new correlation for the effect of molecular weight on the predication of thermal conductivity of gases.     

The Evaluation of Gas,Water, WAG Injections,and Infill Wells for Improving Recovery of an Iranian Reservoir

Abstract

Increasing demand for energy has forced oil companies to resort to secondary and tertiary methods to increase the recovery from the existing reservoirs. The author investigated enhancing the recovery factor of one Iranian reservoir, which is a naturally fractured reservoir. For this reservoir, it is estimated that 96.5% of oil is contained in the matrix and 3.5% in the fractures. The field is an undersaturated reservoir with no active gas cap and no strong water aquifer. Injections of water, gas, water-alternating gas (WAG), and infill wells on this field were investigated to increase the recovery factor. Eclipse100 was employed to simulate the reservoir. The simulated results showed that gas, water, and WAG injections had nonsignificant improvements on oil recovery. However, it was found that infill wells contribute an appreciable increase in recovery. The amount of increase for drilling 8 infill wells was around 5%. Since development of existing resources contributes a major role on the supply of oil for the future oil market (around 45% by 2030), these results are used to screen the various methods for increasing the recovery of such reservoirs.     

利用生产数据计算气井控制储量和水侵量

为了解决水侵量计算较为复杂的问题,根据存水体积系数的物理意义,将存水体积系数用当前气藏含水饱和度与初始含水饱和度的差值来表示,推导了计算气井控制储量和水侵量的公式。利用该公式计算了某水驱气藏3口气井的控制储量和水侵量,结果表明,计算精度与其他常用计算方法相当。利用该公式还计算了该气藏某口气井不同时刻的含水饱和度、单井控制储量及水侵量,结果表明,在一定采出程度条件下,随着气井生产时间的延长,气藏的含水饱和度升高,气井的控制储量和水侵量增大。气井的控制储量与地层压力差、含水饱和度均呈线性关系;水侵量与地层压力差呈线性关系,与气藏含水饱和度呈指数关系。由于该计算方法中求取含水饱和度时要用稳定的生产数据,因此,该计算方法仅适用于生产时间较长的气井。