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Polymer flooding is a mature chemical enhanced oil recovery (CEOR) technology with over forty years of laboratory- and field-scale applications. Nevertheless, polymers exhibit poor performance in carbonates due to their complex nature of mixed-to-oil wettability, high temperature, high salinity, and heterogeneity with low permeability. The main objective of this study is to experimentally evaluate the performance of a biopolymer (Scleroglucan) in carbonates under harsh conditions of temperature and salinity. This experimental investigation includes polymer rheological studies as well as polymer injectivity tests. Rheological studies were performed on the biopolymer samples to measure the polymer viscosity as a function of concentration, shear rate, salinity, and temperature. Injectivity characteristics of this biopolymer were also examined through corefloods using high permeability carbonate outcrops. The injectivity tests consisted of two stages of water pre-flush and polymer injection. These tests were conducted using high salinity formation water (167,000 ppm) and seawater (43,000 ppm) at both room (25 °C) and high temperature (90 °C) conditions.
The rheological tests showed that the biopolymer has a high viscosifying power and it exhibits a shear-thinning behavior that is more prevalent at higher polymer concentrations. Also, a pronounced effect was observed for water salinity on both polymer filterability and polymer injectivity. The biopolymer exhibited better filterability at the high temperature as opposed to the room temperature. From the injectivity tests, the shear-thinning behavior of this biopolymer in the porous media was confirmed as the resistance factor decreased with increasing the flow rate applied. The potential biopolymer showed good injectivity at both the room and the high temperatures. This study provides further insight into the performance of this biopolymer in carbonate reservoirs and encourages further application under harsh conditions of salinity and temperature.
Equilibrium Pc-RI measurements on low permeability core plugs present the SCAL laboratory with some difficult challenges regarding the duration of measurements and the attainment of truly equilibrated resistance readings. A new empirical method is described that allows estimation of fully equilibrated resistance by application of a simple transient data linearizing transform and plot slope analysis. A small set of plugs from a conventional tight gas field in the Sultanate of Oman is used to demonstrate the method. The method may also be used by the lab to monitor and shorten the Pc-RI measurement duration without compromising the interpretation of saturation exponents or capillary curves. Transform plot transients and macro capillary number are examined to estimate a boundary where the plugs transition from shock front rapid desaturation to slow percolation desaturation behavior.
Geothermal energy resources in HDR becomes increasingly attractive due to both environmental and economic reasons. Increasing energy efficiency, hydraulic fracturing has been proposed, which has been extensively applied in petroleum engineering. Both the mechanical response and hydraulic flow coupled to the thermal effects are of great interests in these processes. Transient semi-analytical solutions for temperature and pore pressure and effective stress field near a circular borehole subjected to a non-isothermal constant flow are presented. The solutions couple conductive heat transfer with Darcy fluid flow in a poroelastic medium. They are applicable in low permeability porous media such as heavy oil reservoirs, HDR or shales, where conduction dominates the heat transfer process but a convective heat transfer must be considered for high permeability formations such as sandstones and fractured media where energy transport carried by hydraulic flow velocity can be dominating. Solutions presented show separately the effects of thermal perturbation and fluid flow on fluid pressures and effective stress development. It will be shown that a substantial thermal induced compressive stress may be generated near a borehole, which may prevent a fracture from initiating on the wellbore wall when wellbore temperature is high, whereas enhance a fracturing process when a cooler wellbore fluid in injected. Failure to incorporate such an effect may lead to serious error in designing a Enhanced Geothermal System (EGS) and hydraulic fracture predictions.
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.
Flow zonation and permeability estimation is a common problem in reservoir characterization; usually, integration of openhole log data with conventional and special core analysis solves the latter. We present a Bayesian based method for identifying hydraulic flow units in uncored wells using the theory of Hydraulic Flow Units (HFU) and subsequently compute permeability using wireline log data. First, we use the F-test and the Akaike's criteria coupled with a nonlinear optimization scheme based on the probability plot to determine the optimal number of HFU present in the core dataset with the regression match giving the pertinent statistical parameters of each flow unit.
Geomechanical modeling of hydraulic fracturing in deep gas reservoirs in Oman is complicated by high uncertainties in key parameters. This study aims to adopt a physics-based data analytics technique to model geomechanical behavior of rocks. The paper also presents the methodology of linking geomechanics with well performance. Finally, the integration of the results into a decision support system is discussed.
The majority of deep gas reservoirs in Oman are tight. The permeabilities are in the sub-millidarcy range. Hydraulic fracturing helps to unlock the reserves. Meanwhile, proper hydrofracture design is required to optimize the development of these complex reservoirs. Due to high stresses, unclear processes governing hydrofracture propagation, and complex depositional and diagenetic histories, the applicability of standard hydrofracture modeling techniques becomes questionable. Proper surveillance design and in-depth analysis of the monitoring data assist in testing the range of applicability of the modeling tools. The analysis also aids in characterizing the influence of the processes not captured within the models.
Recently the development of deep gas reservoirs in Oman started to benefit from horizontal well technology. Similarly to other horizontal developments, the question of proper well architechture and stimulation design was raised. In this study, the data pertaining to historical vertical wells was collated to understand the processes governing hydrofracture placement. The data indicated the presence of strong fracture barriers and of highly stressed zones which affect the ability to create sufficient fracture conductivity. Further, geomechanical models were calibrated to allow for realistic estimate of the contact area between the fracture and reservoir. Analysis of the production data indicated that productivity was often limited by the factors not captured in the models (e.g., suboptimal cleanup). For proper planning, risk factors may be chosen to reflect the loss of productivity. In the next step, the learnings from the vertical wells served for characterizing hydrofracturing in horizontals. Analysis of the data indicated that due to near-wellbore complexity and choking effect the productivity of an individual fracture in a horizontal well was only a fraction of that in a vertical well. As a final step all the data along with their interpretation are being incorporated into the library of hydrofracture scenarios. Future development will rely on searching for the analogs and selecting a design fitting all applicable scenarios. The paper presents an overview of the surveillance data analysis. The results of the analysis allow for creating a library of the development scenarios, which serve as a basis for a decision support system aimed at streamlining hydrofracture and well planning design.
Taher, Ahmed (ADNOC Upstream) | Celentano, Maria (ADNOC Upstream) | Franco, Bernardo (ADNOC Upstream) | Al-Shehhi, Mohammed (ADNOC Upstream) | Al Marzooqi, Hassan (ADNOC Upstream) | Al Hanaee, Ahmed (ADNOC Upstream) | Da Silva Caeiro, Maria (ADNOC Upstream)
In early Aptian times, subtle tectonic movements may have been activated along the NW-SE strike-slip faults and have resulted in a vertical displacement along these faults. The displacement would have allowed the carbonate-producing organisms to colonize along the shallower southern margin and generate well developed reservoir facies. The basinal facies were deposited to the north of the shelf margin, which is known to be the Bab Basin.
Significant oil was discovered in the Shuaiba shelf facies. However, the lagoonal and basinal facies have potential for discovering a significant volume of hydrocarbon, especially in the fields that are located in the Upper Thamama hydrocarbon migration pathways. This potential is supported by the absence of an effective seal separating Thamama Zone-A from Shuaiba basinal facies above, which allowed for the Zone-A hydrocarbon to migrate vertically into the Shuaiba basinal facies. In addition, this potential was supported by the hydrocarbon shows while drilling and by the interpreted well logs, which confirm the presence of movable hydrocarbon in the Shuaiba lagoonal and basinal facies.
The Shuaiba Formation is comprised of two supersequences (
The Shuaiba basinal facies were deposited in an intrashelf basin that was enclosed by the Shuaiba shelfal facies sediments. This resulted in restricted water circulation, anoxic condition and deposition below the wave base. Such depositional environment is favourable for source rock preservation.
Lithologically, Shuaiba basinal facies consist of pelagic lime-mudstone, wackestone and packstone with abundant planktonic microfossils. These facies are characterized by low permeability values, but their porosity can reach up to 20%. The lagoonal sediments consists of a deepening sequence of carbonate sediments, with shallow marine algal deposits at the base and fine hemipelagic to pelagic carbonates in the upper section.
The differences between the Shuaiba Shelf and the Shuaiba Basin are mainly in permeability values. By applying the latest technology in horizontal drilling and hydraulic fracturing, the Shuaiba basinal facies will produce a significant volume of hydrocarbon.
Thermal EOR projects are technically and economically challenging projects. Improving the geological understanding and implementing these geological concepts into the static model were key to increase the robustness of, not only the geological model but also of the dynamic simulation.
The initial believe was that fine grained and mm scale laminated sediments act as vertical baffles for the steam distribution. The fine grained sands were low in permeability and the lamination were further reducing the vertical permeability. Grain size had the main impact on permeability and grain size was correlated with V-shale. Then, V-shale was used as a proxy for grain size and was integrated into a V-shale base porosity-permeability transformation.
After modeling the baffles explicitly, it was shown that against the initial belief, the main control on fluid flow was not a patchy baffle distribution. Instead the reservoir was overall reduced in vertical permeability. A lager impact had the V-shale base poro-perm transform, predicting an order of magnitude permeability range for a given porosity. Reducing the impact of the facies also reduced overall the uncertainty and improved the predictive power of the models. This in turn, helped to take development decisions with much higher confidence.
The task of reliable characterization of complex reservoirs is tightly coupled to studying their microstructure at a variety of scales, which requires a departure from traditional petrophysical approaches and delving into the world of nanoscale. A promising method of representatively retaining a large volume of a rock sample while achieving nanoscale resolution is based on multiscale digital rock technology. The smallest scale of this approach is often realized in the form of working with several 3D focused-ion-beam–scanning-electron-microscopy (FIB-SEM) models, registration of these models to a greater volume of rock sample, and estimation and scaling up of model local properties to the volume of the entire sample. However, a justified and automated selection of representative regions for building FIB-SEM models poses a big challenge to a researcher. In this work, our objective was to integrate modern SEM and mineral-mapping technologies to drive a justified decision on location of representative zones for FIB-SEM analysis of a rock sample. The procedure is based on two experimental methods. The first method is automated mapping of sample surface area with the use of backscattered electrons (BSEs) and secondary electrons (SEs); this method has resolution down to nanometers and spatial coverage up to centimeters, also referred to as large-area high-resolution SEM imaging. The second method is automated quantitative mineralogy and petrography scanning that allows covering sample’s cross section with a mineral map, with resolution down to 1 µm/pixel. Data gathered with both methods on millimeter-sized cross sections of rock samples were registered and integrated in the paradigm of joint-data interpretation, augmented with computer-based image-processing techniques, to provide a reliable classification of nanoscale and microscale features on sample cross sections. The superimposed SEM and mineral-map images were combined with physics-based selection criteria for reasonable selection of FIB-SEM candidates out of a great number of potential sites. In the result, a semiautomated work flow was developed and tested. Demonstration of the work flow is made on one of Russia’s most promising tight gas formations, where the characteristic dimension of void-space objects spans from a single nanometer to millimeters. An example of an optimized site selection for FIB-SEM operations is discussed.
Yong, Li (Research Institute of Petroleum Exploration and Development, PetroChina) | Changbing, Tian (Research Institute of Petroleum Exploration and Development, PetroChina) | Baozhu, Li (Research Institute of Petroleum Exploration and Development, PetroChina) | Yixiang, Zhu (Research Institute of Petroleum Exploration and Development, PetroChina) | Benbiao, Song (Research Institute of Petroleum Exploration and Development, PetroChina)
For reservoir development study, there are a lot of uncertainties in different research aspects. But if these uncertainties are ignored, reservoir performance could be much worse than expected because of wrong development options possibly selected and applied. Therefore, uncertainty analysis should be addressed during reservoir development study, and uncertainty parameters should be analyzed and their impact should be evaluated in order to reduce the corresponding risks. The paper proposes that uncertainty analysis should run through the whole study process of reservoir development plan.
Based on the reservoir development stage and reservoir geological features, all related uncertainty factors are identified. And the uncertainty range of each factor are determined with upside, expected and downside values or models. Then all factors are embedded into the static and dynamic models, and the uncertainty impact on reservoir performance are quantitatively evaluated based on the upside, expected and downside dynamic models respectively. After that, uncertainty parameters are ranked into differernt groups.
Take one large multi-layered sandstone oilfield in Middle East for example, uncertainty analysis methods are illustrated. The large sandstone reservoir in Middle East is at its primary depletion development stage with only 5% recovery factor currently, and waterflooding is urgert. Firstly, key uncertainty parameters are determined, which can be mainly classified into two categoriesgeological model and dynamic model. Then according to the characteristic of this reservoir and uncertainties understanding of geological study, 3 static models with same probability are built. After that, uncertainties understanding of dynamic analysis are included into static models, and 3 dynamic models representing Upside, Expected and Downside models are generated in order to fully characterize all the uncertainties. So development options and development schemes optimization can be studied based on the 3 models in order to determine the uncertainties of water flooding performance. Finally the induced risks of each main uncertainty parameter are quantitatively evaluated, and corresponding treatments are proposed.
This paper offers the methodology and a case study on uncertainty analysis and management within the waterflooding development for a large multi-layered sandstone reservoir, and the results are valuable for the following development options decision making. It also provides a reference for uncertainty management of similar reservoir.