Glover, Paul W. J. (University of Leeds) | Lorinczi, Piroska (University of Leeds) | Al-Zainaldin, Saud (University of Leeds) | Al-Ramadhan, Hassan (University of Leeds) | Sinan, Saddam (University of Leeds) | Daniel, George (University of Leeds)
New reservoirs are increasingly more heterogeneous and more anisotropic. Unfortunately, conventional reservoir modelling has a resolution of only about 50 m, which means it cannot be used to model heterogeneous and anisotropic reservoirs effectively when such reservoirs exhibit significant inter-well variability at scales less than 50 m. This paper describes a new fractal approach to the modelling and simulation of heterogeneous and anisotropic reservoirs. This approach includes data at all scales such that it can represent the heterogeneity of the reservoir correctly at each scale.
Three-dimensional Advanced Fractal Reservoir Models (AFRMs) can be generated easily with the appropriate code. This paper will show: (i) how 3D AFRMs can be generated and normalised to represent key petrophysical parameters, (ii) how these models can be used to calculate permeability, synthetic poro-perm cross-plots, water saturation maps and relative permeability curves, (iii) the effect of altering controlled heterogeneity and anisotropy of generic models on fluid production parameters, and (iv) how AFRMs which have been conditioned to represent real reservoirs provide a much better simulated production parameters than the current best technology.
Results of generic modelling and simulation with AFRMs show how total hydrocarbon production, hydrocarbon production rate, water cut and the time to water breakthrough all depend strongly both on heterogeneity and anisotropy. The results also show that in heterogeneous reservoirs, the best production data is obtained from placing both injectors and producers in the most permeable areas of the reservoir – a result which is at variance with common practice. Modelling with different degrees and directions of anisotropy shows how critical hydrocarbon production data depends on the direction of the anisotropy, and how that changes over the lifetime of the reservoir.
We have developed a method of fractal interpolation to condition AFRMs to real reservoirs across a wide scale range. Comparison of the hydrocarbon production characteristics of such an approach to a conventional krigging shows a remarkable improvement in the modelling of hydrocarbon production when AFRMs are used; with AFRMs in moderate and high heterogeneity reservoirs returning values always within 5% of the reference case, while the conventional approach often resulted in systematic underestimations of production rate by over 70%.
Jiang, Li-Wei (PetroChina Zhejiang Oilfield Company) | He, Yong (PetroChina Zhejiang Oilfield Company) | Shu, Dong-Chu (PetroChina Zhejiang Oilfield Company) | Niu, Wei (PetroChina Zhejiang Oilfield Company) | Pan, Feng (Schlumberger) | Wang, Yue (Schlumberger) | Li, Kai-Xuan (Schlumberger) | Zhao, Hai-Peng (Schlumberger) | Tang, Yu (PetroChina Southwest Oil and Gas Company)
Most bedding-parallel fractures in the WuFengLongMaxi Formation, SiChuan basin, are calcite filled and commonly show slickensides, which features characterize bedding-parallel shear fractures. Such fractures can serve as flow channels and storage spaces in gas shale reservoirs. However, little is known about their size and spatial distribution, the relationship of their permeability to the confining stress, and any relationship with porosity. Knowing these relationships may contribute to understanding the role of bedding-parallel shear fractures in shale gas enrichment.
Bedding-parallel shear fractures were measured from core and image logs from the WuFeng-LongMaxi Formation, southern SiChuan basin, supplemented with stress-dependent permeability experimental data and nuclear magnetic resonance (NMR) logs from the same wells. Core and image logs were used to characterize the spatial organization of the fractures. A stress-dependent permeability experiment was proposed to investigate the fracture permeability response to changes in confining stress. The effect of the fractures on porosity was examined in terms of the macroporous component reflected by the NMR T2 relaxation; macropores are more likely to be preserved in gas-rich shale. Study of 27 wells spanning 100 km west-east across the southern SiChuan basin revealed the aperture size of bedding-parallel shear fractures ranges from 1 cm to 50 cm. In most wells, the fractures are much more intense in organic-rich intervals, which have low elastic modulus compared to the overlying nonorganic shale and underlying stiff limestone. The stress-dependent permeability experiment suggests that permeability in samples with the fractures is two to three orders of magnitude larger than in samples without fractures under the same confining stress. Fracture permeability decreases exponentially until the confining stress reaches 25 MPa. NMR analysis indicates that the macroporous component has an inverse relationship with the intensity of bedding-parallel shear fractures.
Application of polymer flooding as a chemical Enhanced Oil Recovery (EOR) has increased over recent years. The main type of polymer used is partially hydrolyzed polyacrylamide (HPAM). This polymer still has some challenges especially with shear stability and injectivity that restrict its utility, particularly for low permeability reservoirs. Injectivity limits the possible gain by acceleration in oil production due to polymer flooding. Hence, good polymer injectivity is a requirement for the success of the operation. This paper aims to investigate the influence of formation permeability on polymer flow in porous media.
In this study, a combination of core flooding with rheological studies is presented to evaluate the influence of permeability on polymer in-situ rheology behavior. The in-situ flow of HPAM polymers has also been studied for different molecular weights. The effect of polymer preconditioning prior to injection was studied through exposing polymer solutions to different extent of mechanical degradation.
Results from this study reveal that the expected shear thinning behavior of HPAM that is observed in rheometer measurements is not observed in in-situ rheology in porous media. Instead, HPAM in porous media exhibits near-Newtonian behavior at low flow rates representative of velocities deep in the reservoir, while exhibiting shear thickening behavior at high flow rates representative of velocities near wellbore region. The pressure build-up associated with shear thickening behavior during polymer injection is significantly higher than pressure differential during water injection. The extent of shear thickening is high during the injection of high Mw polymer regardless of cores' permeability. In low permeable Berea cores, shear thickening and mechanical degradation occur at lower velocities although the degree of shear thickening is lower in Berea to that observed in high permeable Bentheimer cores. This is ascribed to high polymer retention in Berea cores that results in high residual resistance factor (RRF). Results show that preshearing polymer before injection into porous media optimizes its injectability and transportability through porous media. The effect of preshearing becomes favorable for the injection of high Mw polymers into low permeability formation.
This study discusses polymer in-situ rheology and injectivity, which is a key issue in the design of polymer flood projects. The results provide beneficial information on optimizing polymer injectivity, in particular, for low permeability porous media.
Many gas reservoirs at the appraisal stage exhibit evidence of persistent gas saturations below free water levels (FWL's). The amounts of gas contained here may, under some situations, be a sizable fraction of the gas cap volumes. Many engineers appear poorly equipped to include, and model, paleo gas in simulation models. This often results in paleo gas being simply ignored when development plans are being considered. This is unfortunate because paleo gas upon pressure depletion can expand, displacing brine towards well completions. This means that while some additional gas production may occur from the paleo zone, the risk of water production may be significantly underestimated if paleo gas is simply omitted. This work discusses the evidence for paleo gas and shows that it may be described and incorporated in simple simulation models provided the user avoids some common misconceptions. It is demonstrated that under depletion conditions, paleo gas can be entirely visible to material balance pressure responses, while at the same time increasing the risk of produced water volumes. For higher pressure paleo gas reservoirs the common P on Z diagnostic plots can also provide early trends that are frequently misinterpreted. This work quantifies the curvature that can result in such systems, and shows that simulation models inherently predict the expected curvature in P on Z. The approach taken here is by design simplistic and is applicable to scoping evaluations where the paleo gas volumes could be a significant volumetric uncertainty. Where possible, we indicate where additional, or more rigorous, descriptions can be applied.
As an enhanced oil recovery method (EOR), chemical flooding has been implemented intensively for some years. Low Salinity WaterFlooding (LSWF) is a method that has become increasingly attractive. The prediction of reservoir behaviour can be made through numerical simulations and greatly helps with field management decisions. Simulations can be costly to run however and also incur numerical errors. Historically, analytical solutions were developed for the flow equations for waterflooding conditions, particularly for non-communicating strata. These have not yet been extended to chemical flooding which we do here, particularly for LSWF. Dispersion effects within layers also affect these solutions and we include these in this work.
Using fractional flow theory, we derive a mathematical solution to the flow equations for a set of layers to predict fluid flow and solute transport. Analytical solutions tell us the location of the lead (formation) waterfront in each layer. Previously, we developed a correction to this to include the effects of numerical and physical dispersion, based on one dimensional models. We used a similar correction to predict the location of the second waterfront in each layer which is induced by the chemical's effect on mobility. In this work we show that in multiple non-communicating layers, material balance can be used to deduce the inter-layer relationships of the various fronts that form. This is based on similar analysis developed for waterflooding although the calculations are more complex because of the development of multiple fronts.
The result is a predictive tool that we compare to numerical simulations and the precision is very good. Layers with contrasting petrophysical properties and wettability are considered. We also investigate the relationship between the fractional flow, effective salinity range, salinity dispersion and salinity retardation.
This work allows us to predict fluids and solute behaviour in reservoirs with non-communicating strata without running a simulator. The recovery factor and vertical sweeping efficiency are also very predictable. This helps us to upscale LSWF by deriving pseudo relative permeability based on our extension of fractional flow and solute transport into such 2D systems.
Engineers need to predict the production characteristics from hydraulically fractured wells in tight gas fields. Decline curve analysis (DCA) has been widely used over many years in conventional oil and gas fields. It is often applied to tight gas, but there is uncertainty regarding the period of production data needed for accurate prediction.
In this paper decline curve analysis of simulated production data from models of hydraulically fractured wells is used to to develop improved methods for calibrating decline curve parameters from production data. The well models were constructed using data from the Khazzan field in Oman. The impact of layering, permeability and drainage area on well performance is also investigated. The contribution of each layer to recovery and the mechanisms controlling that contribution is explored.
The investigation shows that increasing the amount of production data used to fit a hyperbolic decline curve does not improve predictions of recovery unless that data comes from many years (20 years for a 1mD reservoir) of production. This is because there is a long period of transient flow in tight gas reservoirs that biases the fitting and results in incorrect predictions of late time performance. Better predictions can be made by estimating the time at which boundary dominated flow is first observed (tb), omitting the preceding transient data and fitting the decline curve to a shorter interval of data starting at tb. For single layer cases, tb can be estimated analytically using the permeability, porosity, compressibility and length scale of the drainage volume associated with the well. Alternatively, tb can be determined from the production data allowing improved prediction of performance from 2-layer reservoirs provided that a) there is high cross-flow or b) there is no cross-flow and the lower permeability layer either does not experience BDF during the field life time or it is established quickly.
Hadi, Farqad (Petroleum Engineering Department, Baghdad University) | Albehadili, Ali (Iraqi Drilling Company) | Jassim, Abduihussein (Najaf Oil Fields) | Almahdawi, Faleh (Petroleum Engineering Department, Baghdad University)
Formulating a prediction tool that can estimate the formation permeability in uncored wells is of particular importance for many applications related to reservoir simulation and production management. Although formation permeability can be obtained from a laboratory or from a reservoir, core analysis and well-test data are limited due to cost and time-saving purposes. A major challenge of previous methods is that they are required other parameters to be previously computed such as porosity and water saturation. In addition, they are affected by the uncertainty that introduced by the cementation factor and saturation exponent. This study presents two prediction methods, multiple regression analysis (MRA) and artificial neural networks (ANNs), to estimate formation permeability using conventional well log data.
The prediction methods were demonstrated by means of a field case in SE Iraq. The study uses core/well log data from Mishrif reservoir which is mainly composed of carbonate (limestone) formations. Two traditional methods were reviewed and presented for permeability determination. These methods are the classical method and the flow zone indicator (FZI) method.
At the same porosity, the results showed a wide range of formation permeability prediction. This result gives a special attention to the assumption that the relationship between permeability and porosity is generally unique in carbonate environments. The deep lateral log resistivity appears to be more conservative in the permeability function rather than other parameters, followed in decreasing order by bulk density, sonic travel time, micro and shallow resistivities, and shale volume. Although the presented models based on RA and ANNs resemble to be closely in determining the formation permeability, the correlation coefficient of ANNs was found to be higher than that obtained from RA, which indicated that the ANNs is more precise than RA. The comparison among previous methods shows the superiority of the FZI method rather than the classical method. However, core porosity and permeability should be previously determined to apply FZI method. This study presents efficient and cost-effective models for a prediction of permeability in uncored wells by incorporating conventional well logs.
Pola, Jackson (Heriot-Watt University) | Geiger, Sebastian (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Bentley, Mark (Heriot-Watt University) | Maier, Christine (Heriot-Watt University) | Al-Rudaini, Ali (Heriot-Watt University)
We investigate how efficiently oil can be recovered from a carbonate rock during surfactant based enhanced oil recovery (EOR) at the core-scale, particularly when chemical processes change wettability, and analyse how geological heterogeneities, observed at the next larger scale (centimetre to decimetre) impacts the effectiveness of surfactant-based EOR at the inter-well scale.
To quantify how heterogeneity across scales impacts surfactant flooding, we combine laboratory experiments with simulation studies at the core- and inter-well scale. We first analysed a series of surfactant imbibition experiments at different surfactant concentrations (from 0 to 3 wt. %) using reservoir cores from the Wakamuk field, a carbonate reservoir in Indonesia. We then built a 3D simulation model of the laboratory experiment and matched the experimental data to identify the key physical mechanisms (e.g., reduction in interfacial tension (IFT) and wettability alteration) that lead to increased oil recovery. Next, we parametrised the surfactant models using assisted history-matching methods to calibrate the relative permeability and capillary pressure curves as a function of surfactant concentration. These models were then deployed in high-resolution simulations at the inter-well scale. These simulations captured the small-scale geological heterogeneities that are typical for a carbonate reservoir system, e.g., the Shuaiba formation in the Middle East, but are not resolved in field-scale models.
Our core-scale simulations demonstrate a change from co- to counter-current flow in the laboratory experiments and indicate that the resulting increase in oil recovery is due to a combination of IFT reduction, wettability alteration from oil- to water-wet, and capillary pressure restoration; these processes need to be captured adequately at the inter-well scale model. The increase in surfactant concentration above the critical micelle concentration (CMC) (i.e., from 1 to 3 wt. %) triggered the capillary pressure restoration and dominated recovery at the early-time. The changes in relative permeability and capillary curves during the surfactant floods were best modelled using a concentration-based interpolation. There is uncertainty when calibrating surfactant models using laboratory experiments. A key question hence is if geological heterogeneity at the inter-well scale masks these uncertainties.
Results from our high-resolution simulations show that large-scale heterogeneity impacts recovery predictions, but it is the coarsening of the grid, not the upscaling of permeability, that dominates the error in field-scale recovery predictions during surfactant based EOR. Indeed, the error arising from numerical dispersion during grid coarsening can be as large as the error arising when selecting an inaccurately configured surfactant model due to the lack of quality experimental data. Hence appropriate grid refinement, possibly using adaptive grid refinement, needs to be considered when setting up a surfactant based EOR simulation, along with the appropriate configuration of the surfactant model itself.
Baruah, Nabajit (Oil & Natural Gas Corporation) | Mandal, Dipak (Oil & Natural Gas Corporation) | Jena, Smita Swarupa (Oil & Natural Gas Corporation) | Sahu, Sunil Kumar (Oil & Natural Gas Corporation)
This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.
Sun, Zheng (China University of Petroleum at Beijing, Texas A&M University) | Shi, Juntai (China University of Petroleum at Beijing) | Wu, Keliu (China University of Petroleum at Beijing) | Gong, Dahong (CNPC Bohai Drilling Engineering Company Limited Directional Well Technology Services Branch) | Peng, Hui (CNPC Bohai Drilling Engineering Company Limited Mud Logging 2) | Hou, Yuhua (NO.2 Logging Branch of Bohai Drilling Engineering Co., Ltd., PetroChina Group) | Ma, Hongyan (CNPC Bohai Drilling Engineering Company Limited Directional Well Technology Services Branch) | Wang, Daning (CNPC Bohai Drilling Engineering Company Limited Directional Well Technology Services Branch) | Ramachandran, Hariharan (The University of Texas at Austin) | Liu, Yisheng (China University of Petroleum at Beijing) | Liu, Wenyuan (China University of Petroleum at Beijing) | Wang, Suran (China University of Petroleum at Beijing) | Li, Xiangfang (China University of Petroleum at Beijing)
With respect to the sharp increase in population all around the world, more and more energy and fuels are expected to achieve the counterbalance between supply and demand. Deeply attracted by its considerable and prospect recovery reserve, the exploitation, development and related research contents regarding coalbed methane (CBM), i.e., one of the unconventional gas reservoirs, are currently heat and essential topics. Without any doubt, precise determination of coal permeability will dramatically contribute to the development efficiency of CBM reservoirs. It should be noted that the permeability in CBM reservoirs possesses unique heterogeneous characteristics, especially for the different permeability at directions of face cleats and butt cleats, which will inevitably result in greatly shape-change for fluid flow field and eventually the production performance. To my best knowledge, nearly all the previous methods proposed for evaluating coal permeability assume the homogeneous permeability feature in CBM reservoirs, which show fairly great discrepancy compared with that of the realistic situation. In this work, in order to address this urgent issue, a novel permeability evaluation method is developed for the first time, which is able to generate precisely heterogeneous characteristics of coal permeability based on the water production rate versus production time curve at the early production stage. First of all, considering both orthotropic heterogeneous permeability and pressure propagation behavior in CBM reservoirs, single water phase productivity equation is seriously derived. Secondly, for simply usage purpose in field application, the obtained equation is transformed through linearization treat. Finally, combining the water production performance with the linearized equation, efficient iteration calculation procedures are given to determine the heterogeneous permeability feature. Also, the skin factor of corresponding CBM well can be determined. The applicability and accuracy of the proposed method have been successfully verified through field application. In sum, the proposed method can serve as a simple as well as an accurate tool to determine the crucial heterogeneous permeability feature in CBM reservoirs. More importantly, during the determination process, the method just requires the water production performance at the early production stage, which means that the obtained permeability characteristics can be utilized to guide production strategy adjustment in the following gas production stage. As a result, the proposed method can be regarded as a necessary preparatory work before gas production takes place in CBM reservoirs, which will play a positive and active role in optimization of ultimate gas recovery and well configuration.