scholarly journals Impact of modelling decisions and rock typing schemes on oil in place estimates in a giant carbonate reservoir in the Middle East

2021 ◽  
pp. petgeo2021-028
Author(s):  
Mohamed AlBreiki ◽  
Sebastian Geiger ◽  
Patrick Corbett
Keyword(s):  
Middle East ◽  
Detailed Analysis ◽  
History Matching ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Base Case ◽  
Single Base ◽  
Rock Typing ◽  
The Impact ◽  
Compare And Contrast

We demonstrate how modelling decisions for a giant carbonate reservoir with a thick transition zone in the Middle East, most notably the approach to reservoir rock typing and modelling the initial fluid saturations, impact the hydrocarbon distributions and oil-in-place estimates in the reservoir. Rather than anchoring our model around a single base case with an upside and downside, we apply a comprehensive 3D multiple deterministic scenario workflow to compare-and-contrast how modelling decisions and geological uncertainties influence the volumetric estimates. We carry out a detailed analysis which shows that the variations in STOIIP estimates can be as high as 28% depending on the preferred modelling decision, which could potentially mask the impact of other geological uncertainties. These models were validated through repeated and randomised blind tests. We hence present a quantitative approach that helps us to assess if the static models are consistent in terms of the integration of geological and petrophysical data. Ultimately, the decision which of the different modelling options should be applied does not only influence STOIIP estimates, but also subsequent history matching & forecasts.

Injectivity and Propagation of Sulfonated Acrylamide-Based Copolymers in Low Permeability Carbonate Reservoir Cores in Harsh Salinity and Temperature Conditions : Challenges and Learnings from a Middle East Onshore Case Study

2021 ◽  
Author(s):  
Nicolas Gaillard ◽  
Matthieu Olivaud ◽  
Alain Zaitoun ◽  
Mahmoud Ould-Metidji ◽  
Guillaume Dupuis ◽  
...  
Keyword(s):  
Middle East ◽  
Polymer Solutions ◽  
Carbonate Reservoir ◽  
Core Material ◽  
Low Permeability ◽  
The Core ◽  
Reservoir Conditions ◽  
Carbonate Cores ◽  
The Impact ◽  
Mobility Reduction

Abstract Polymer flooding is one of the most mature EOR technology applied successfully in a broad range of reservoir conditions. The last developments made in polymer chemistries allowed pushing the boundaries of applicability towards higher temperature and salinity carbonate reservoirs. Specifically designed sulfonated acrylamide-based copolymers (SPAM) have been proven to be stable for more than one year at 120°C and are the best candidates to comply with Middle East carbonate reservoir conditions. Numerous studies have shown good injectivity and propagation properties of SPAM in carbonate cores with permeabilities ranging from 70 to 150 mD in presence of oil. This study aims at providing new insights on the propagation of SPAM in carbonate reservoir cores having permeabilities ranging between 10 and 40 mD. Polymer screening was performed in the conditions of ADNOC onshore carbonate reservoir using a 260 g/L TDS synthetic formation brine together with oil and core material from the reservoir. All the experiments were performed at residual oil saturation (Sor). The experimental approach aimed at reproducing the transport of the polymer entering the reservoir from the sand face up to a certain depth. Three reservoir coreflood experiments were performed in series at increasing temperatures and decreasing rates to mimic the progression of the polymer in the reservoir with a radial velocity profile. A polymer solution at 2000 ppm was injected in the first core at 100 mL/h and 40°C. Effluents were collected and injected in the second core at 20 mL/h and 70°C. Effluents were collected again and injected in the third core at 4 mL/h and 120°C. A further innovative approach using reservoir minicores (6 mm length disks) was also implemented to screen the impact of different parameters such as Sor, molecular weight and prefiltration step on the injectivity of the polymer solutions. According to minicores data, shearing of the polymer should help to ensure good propagation and avoid pressure build-up at the core inlet. This result was confirmed through an injection in a larger core at Sor and at 120°C. When comparing the injection of sheared and unsheared polymer at the same concentration, core inlet impairment was suppressed with the sheared polymer and the same range of mobility reduction (Rm) was achieved in the internal section of the core although viscosity was lower for the sheared polymer. Such result indicates that shearing is an efficient way to improve injectivity while maximizing the mobility reduction by suppressing the loss of product by filtration/retention at the core inlet. This paper gives new insights concerning SPAM rheology in low permeability carbonate cores. Additionally, it provides an innovative and easier approach for screening polymer solutions to anticipate their propagation in more advanced coreflooding experiments.

Simultaneous Interpretation of Three-Phase Relative Permeability and Capillary Pressure for a Tight Carbonate Reservoir From Wireline Formation Testing

2019 ◽  
Vol 142 (6) ◽  
Author(s):  
Xiangnan Liu ◽  
Daoyong Yang
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
History Matching ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Fluid Saturation ◽  
Three Phase ◽  
Tight Carbonate ◽  
Wet Condition ◽  
Oil Gas

Abstract In this paper, techniques have been developed to interpret three-phase relative permeability and water–oil capillary pressure simultaneously in a tight carbonate reservoir from numerically simulating wireline formation tester (WFT) measurements. A high-resolution cylindrical near-wellbore model is built based on a set of pressures and flow rates collected by dual packer WFT in a tight carbonate reservoir. The grid quality is validated, the effective thickness of the WFT measurements is examined, and the effectiveness of the techniques is confirmed prior to performing history matching for both the measured pressure drawdown and buildup profiles. Water–oil relative permeability, oil–gas relative permeability, and water–oil capillary pressure are interpreted based on power-law functions and under the assumption of a water-wet reservoir and an oil-wet reservoir, respectively. Subsequently, three-phase relative permeability for the oil phase is determined using the modified Stone II model. Both the relative permeability and the capillary pressure of a water–oil system interpreted under an oil-wet condition match well with the measured relative permeability and capillary pressure of a similar reservoir rock type collected from the literature, while the relative permeability of an oil–gas system and the three-phase relative permeability bear a relatively high uncertainty. Not only is the reservoir determined as oil-wet but also the initial oil saturation is found to impose an impact on the interpreted water relative permeability under an oil-wet condition. Changes in water and oil viscosities and mud filtrate invasion depth affect the range of the movable fluid saturation of the interpreted water–oil relative permeabilities.

scholarly journals Integrated rock typing and pore facies analyses in a heterogeneous carbonate for saturation height modelling, a case study from Fahliyan Formation, the Persian Gulf

2021 ◽  
Vol 11 (4) ◽  
pp. 1577-1595
Author(s):  
Rasoul Ranjbar-Karami ◽  
Parisa Tavoosi Iraj ◽  
Hamzeh Mehrabi
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
High Energy ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Initial Water ◽  
Rock Types ◽  
Rock Typing ◽  
Pore Types ◽  
Fitting Parameters

AbstractKnowledge of initial fluids saturation has great importance in hydrocarbon reservoir analysis and modelling. Distribution of initial water saturation (Swi) in 3D models dictates the original oil in place (STOIIP), which consequently influences reserve estimation and dynamic modelling. Calculation of initial water saturation in heterogeneous carbonate reservoirs always is a challenging task, because these reservoirs have complex depositional and diagenetic history with a complex pore network. This paper aims to model the initial water saturation in a pore facies framework, in a heterogeneous carbonate reservoir. Petrographic studies were accomplished to define depositional facies, diagenetic features and pore types. Accordingly, isolated pores are dominant in the upper parts, while the lower intervals contain more interconnected interparticle pore types. Generally, in the upper and middle parts of the reservoir, diagenetic alterations such as cementation and compaction decreased the primary reservoir potential. However, in the lower interval, which mainly includes high-energy shoal facies, high reservoir quality was formed by primary interparticle pores and secondary dissolution moulds and vugs. Using huge number of primary drainage mercury injection capillary pressure tests, we evaluate the ability of FZI, r35Winland, r35Pittman, FZI* and Lucia’s petrophysical classes in definition of rock types. Results show that recently introduced rock typing method is an efficient way to classify samples into petrophysical rock types with same pore characteristics. Moreover, as in this study MICP data were available from every one meter of reservoir interval, results show that using FZI* method much more representative sample can be selected for SCAL laboratory tests, in case of limitation in number of SCAL tests samples. Integration of petrographic analyses with routine (RCAL) and special (SCAL) core data resulted in recognition of four pore facies in the studied reservoir. Finally, in order to model initial water saturation, capillary pressure data were averaged in each pore facies which was defined by FZI* method and using a nonlinear curve fitting approach, fitting parameters (M and C) were extracted. Finally, relationship between fitting parameters and porosity in core samples was used to model initial water saturation in wells and between wells. As permeability prediction and reservoir rock typing are challenging tasks, findings of this study help to model initial water saturation using log-derived porosity.

scholarly journals Oil recovery for fractured-vuggy carbonate reservoirs by cyclic water huff and puff: performance analysis and prediction

2019 ◽  
Vol 9 (1) ◽  
Author(s):  
Daigang Wang ◽  
Jingjing Sun
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
High Efficiency ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Production Performance ◽  
Quantitative Prediction ◽  
Attractive Alternative ◽  
Marquardt Algorithm ◽  
The Impact

Abstract Cyclic water huff and puff (CWHP) has proven to be an attractive alternative to improve oil production performance after depletion-drive recovery in fractured-vuggy carbonate reservoirs. However, due to the impact of strong heterogeneity, multiple types of fractured-vuggy medium, poor connectivity, complex flow behaviors and oil-water relationship, CWHP is merely suitable for specific types of natural fractured-vuggy medium, usually causing a great difference in actual oil-yielding effect. It remains a great challenge for accurate evaluation of CWHP adaptability and quantitative prediction of production performance in fractured-vuggy carbonate reservoir, which severely restricts the application of CWHP. For this study, we firstly enable the newly developed fuzzy grey relational analysis to quantify the adaptability of CWHP. With production history of several targeted producers, the accuracy of the proposed method is validated. Based on the traditional percolation theory and waterflood mechanisms in various types of fractured-vuggy medium, a quantitative prediction model for cyclic water cut fwp and increased recovery factor ΔR is presented. The CWHP production performance is discussed by using the Levenberg-Marquardt algorithm for history matching. With a better understanding of the fwp ~ ΔR curve characteristics in different types of fractured-vuggy medium, proper strategies or measures for potential-tapping remaining oil are provided. This methodology can also offer a good basis for engineers and geologists to develop other similar reservoirs with high efficiency.

A New Approach to Simulation of Wax Precipitation During Cold Water Injection in Carbonate Reservoir of Kharyaga Oilfield

2021 ◽  
Author(s):  
Yuri Mikhailovich Trushin ◽  
Anton Sergeevich Aleshchenko ◽  
Oleg Nikolaevich Zoshchenko ◽  
Mark Suleimanovich Arsamakov ◽  
Ivan Vasilevich Tkachev ◽  
...  
Keyword(s):  
Cold Water ◽  
Water Injection ◽  
Carbonate Reservoir ◽  
Hot Water ◽  
Reservoir Rock ◽  
Laboratory Studies ◽  
Wax Deposition ◽  
Field Development ◽  
Sector Model ◽  
The Impact

Abstract The paper describes a methodology for assessing the impact of wax deposition in reservoir oil during cold water injection into heterogeneous carbonate reservoir D3-III of the Kharyaga field. The main goal is to determine the optimal amount of hot water that must be injected before switching to cold water without affecting the field development. The paper presents the results of laboratory studies to determine the thermophysical properties of oil, samples of net reservoir and non-reservoir rock, as well as the results of laboratory studies to determine the conditions and nature of wax deposition in oil when the temperature and pressure conditions change. Calculations were carried out to describe the physical model of oil displacement by water of various temperatures. A series of synthetic sector model runs was performed, which includes the average properties of the selected reservoir and the results of laboratory studies in order to determine the effect of cold water injection on the development performance.

scholarly journals Numerical Simulation Modeling of Carbonate Reservoir Based on Rock Type

2017 ◽  
Vol 2017 ◽  
pp. 1-6 ◽  
Author(s):  
Peiqing Lian ◽  
Cuiyu Ma ◽  
Bingyu Ji ◽  
Taizhong Duan ◽  
Xuequn Tan
Keyword(s):  
History Matching ◽  
Water Saturation ◽  
Rock Type ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Column Height ◽  
Fluid Distribution ◽  
Type Model ◽  
Type Curves ◽  
Rock Types

There are many types of carbonate reservoir rock spaces with complex shapes, and their primary pore structure changes dramatically. In order to describe the heterogeneity of K carbonate reservoir, equations of porosity, permeability and pore throat radii under different mercury injection saturations are fitted, and it shows that 30% is the best percentile. R30 method is presented for rock typing, and six rock types are divided according to R30 value of plugs. The porosity-permeability relationship is established for each rock type, and their relevant flow characteristics of each rock type have been studied. Logs are utilized to predict rock types of noncored wells, and a three-dimensional (3D) rock type model has been established based on the well rock type curves and the sedimentary facies constraint. Based on the relationship between J function and water saturation, the formula of water saturation, porosity, permeability, and oil column height can be obtained by multiple regressions for each rock type. Then, the water saturation is calculated for each grid, and a 3D water saturation model is established. The model can reflect the formation heterogeneity and the fluid distribution, and its accuracy is verified by the history matching.

Sign in / Sign up

Export Citation Format

Share Document