Among the key uncertainties and risks as part of development of a high CO2 offshore gas carbonate field; production well deliverability, produced CO2 management, and cap rock integrity have been identified as potential techno-commercial showstoppers that need further appraisal and studies. CO2 storage and sequestration in the aquifer of the same field was identified as the most feasible and economic option for the Produced CO2 management and hence the injectivity within the targeted intervals and aquifer become part of the appraisal and study scope.
An extensive over 200 m coring program covering various intervals including overburden, caprock, carbonate hydrocarbon intervals and aquifer has been designed as part of data acquisition and surveillance plan. The main plan scope were designed as: To establish reservoir properties & characterization To measure formation pressure and acquire fluid sample To establish reservoir injectivity and productivity at the prospective intervals To acquire data for flow assurance analysis, facilities design and well material selection studies for development planning.
To establish reservoir properties & characterization
To measure formation pressure and acquire fluid sample
To establish reservoir injectivity and productivity at the prospective intervals
To acquire data for flow assurance analysis, facilities design and well material selection studies for development planning.
The test and analysis has been successfully conducted covering the intended scope of the plan. Based on the Well test and PTA, the reservoir permeability is calculated and is more or less aligned with the core permeability with the total high skin which the majority comes from geometrical/limited-entry skin. The productivity index is calculated to be 21 STB/day/psi. There is difficulty to analyze the Injectivity test due to non-isothermal effects during injection and fall-off test where the fluid property of both injected water and reservoir water is a function of temperature and time. An approximate method is applied using the average temperature during the fall-off to simplify the case by considering a constant fluid property. Injectivity Index is estimated from rate and pressure data to be around 26 STB/day/psi. However, it declined by time to reach a value close to 13 STB/day/psi. In the second test, Based on pressure transient analysis the homogeneous, vertical well with limited entry, and infinite boundary model with underneath aquifer was accepted as representative for S2 reservoir. To capture the non-Darcy effect, the rate dependent skin model is selected. Non-Darcy coefficient is extracted from well model for IRP in well model (1.0073E-4 (Mscf/day)-1.
Generally, the well test and injectivity and productivity analysis objectives are achieved as the fluid type is also confirmed. The paper will detail out the actual test results, methodology and evaluation approaches in this surveillance plan.
Rate Transient Analysis (RTA) has been used in gas reservoirs as a proven method for reserve estimation, well diagnostic and production performance evaluations. The authors have demonstrated several case studies showing the application of production analysis (PA) for reservoir characterization in gas and single phase oil reservoirs previously (
These methods were found to be extremely powerful and popular particularly with the high resolution data from pressure downhole gauges (PDG).
In this paper we have analyzed the available production data from a gas reservoir in offshore environment in South East Asia. It has been developed with five high PI wells and smart completion and monitored closely with PDG and other surveillance data to understand the contact movement during the production history. Due to the complexity of the field, different methods of production data analysis were used to understand the production performances. The recent advances in RTA allows us to apply the classical single well analysis method to a multiple well and multiple phase flow using Generalized Pseudo Pressure (GPP).
The previously published workflow by the authors (
In order to design and analyse Alkaline Surfactant Polymer (ASP) pilots and generate reliable field forecasts, a robust scalable modeling workflow for the ASP process is required. Accurate modeling of an ASP flood requires detailed representation of the geochemistry and the saponification process, if natural acids are present. The objective of this study is to extend the existing models of ion exchange and surfactant partitioning between phases to improve the quality of the model.
Geochemistry and saponification affect the propagation of the injected chemicals. This in turn determine the chemical phase behaviour and hence the effectiveness of the ASP process. A starting point of such a workflow is to carry out ASP coreflood tests and history matching (HM) using numerical models. This allows validation of the models and generates a set of chemical flood parameters that can be used for forecasts. The next step is upscaling from lab to field. The presence of (geo)-chemistry in ASP model improves significantly the quality of core HM especially for produced chemicals, breakthrough time and their profiles shape.
The addition of surfactant partitioning between the oleic and the aqueous phases based on salinity of the system as well as propagated distance (time) improves understanding of the required surfactant concentration. The partitioning of surfactant is important for coreflood matching of native cores as they tend to have more clays and minerals that affect ASP phase behaviour. The upscaling of the HM coreflood was conducted in two steps. First step the coreflood was scaled up with the distance between injector–producer pair as the scaling parameter. Second step was the application of the scaled up injection rates, residual saturations, etc. to the full field model. Sensitivity study for parameters such as grid size, well distance, ASP slug size, and rate of surfactant partitioning was performed. It was found that grid size of 50ft was optimum for ASP modeling. The higher rate of surfactant partitioning resulted to lower recovery. The optimal well distance was determined as 700ft for optimization of oil recovery. The reduction of ASP slug size from 0.5PV to 0.3PV leads to the reduction in oil recovery by 2-3%.
Usually chemical reactions accompanied ASP process are left out of the model due to increase in complexity as well as longer computational time. However, their addition as well as presence of surfactant partitioning between the oleic and the aqueous phases makes ASP models more realistic and it results in significant improvement to coreflood HM quality and prediction of ASP process.
Production data analysis is the key to provide pertinent reservoir information in-terms of reservoir container volume, depletion mechanism, reservoir connectivity and well performances. This study focused on the analytical methods such as Rate Transient Analysis (RTA), Flowing Material Balance (FMB), Pressure Transient Analysis (PTA) and analytical simulation as an integrated approach toward enhanced production data analysis in the oil fields. The idea of FMB has been introduced by
In this paper, the above mentioned methods and workflow is elaborated and a case study using this integrated approach is discussed for better understanding of the methodology.
Integrated reservoir modeling with representative data is crucial for an effective reservoir management and depletion plan. Both analytical and numerical approaches benefit from this integrated process. The objective of this study is to incorporate the outcomes of analytical techniques such as rate transient analysis (RTA) and pressure transient analysis (PTA) into numerical reservoir model to have a better understanding of drive mechanisms, reservoir connectivity with minimal time-consuming for history matching efforts but a more reliable production forecast.
In order to demonstrate the methodology, a clastic reservoir from Malay basin was considered. Sedimentology and sequence stratigraphy studies were performed to have a better picture of heterogeneity and zonation of the reservoir. All production and injection data were investigated along with pressure data to filter data inconsistency. Shut-in time should be long enough to take representative reservoir pressure and accordingly material balance study conducted for accessible volume for a given area. However, flowing material balance is able to be applied with no restriction on the production data for evaluation of historical data and prediction cases.
The boundary of the channel sand was constructed based on the well log data and seismic attributes. Amplitude impedance was used as a guide for lithofacies and porosity distribution in the geological model. In addition, stratigraphy definition with further details were incorporated. Lithofacies, petrophysical and SCAL data were incorporated in rock-type classification and accordingly saturation-height-function were modelled. Analytical approaches including PTA, material balance, and RTA were utilized to have a better understanding of fluid flow and drive mechanisms. The well and reservoir properties and also connected volume from analytical approaches were utilized as a tuning tool of static model. This approach considerably reduced the iteration between static and dynamic models for history matching exercise. Afterwards, the production forecast were conducted with two development opportunities identified.
In this study, an integrated methodology was applied to mitigate the complexity of history matching task. Moreover, it is demonstrated that using such analytical methods help to improve the development plan of a given field significantly.
Ezabadi, Mehdi Ghane (PETRONAS Carigali Sdn. Bhd.) | Ataei, Abdolrahim (PETRONAS Carigali Sdn. Bhd.) | Liang, Tan Kok (PETRONAS Carigali Sdn. Bhd.) | Motaei, Eghbal (PETRONAS Carigali Sdn. Bhd.) | Othman, Tg Rasidi Tg (PETRONAS Carigali Sdn. Bhd.)
Production Data Analysis (PDA) has been widely accepted as a valuable analytical tool for well performance evaluation, production forecasting and reservoir characterization. It is fast, practical, and inexpensiveand it can answer many questions about the connected volume to the well, flow regime, average permeability and skin, as well as any boundary within the radius of investigation of the well. It becomes even more important in the case of complex systems such as finely laminated sand reservoirs, or highly heterogeneous multi-stacked reservoirs where sometimes numerical simulation model miscarries in predicting the reservoir performance.
Analytical approaches for PDA are variants and require different levels of details in the input. Each is established based on certain assumptions and concepts, and comes with specific limitations. Despite overlap amongst the various methods, each has an advantage in particular application over the others. Therefore, one must be vigilant to use each method for the right purposes in addition to confirm the results and unveil possible uncertainties through using several different methods.
This paper integrates basic production and reservoir data through different platforms and methods. Diagnostic plots, General Material Balance (GMB), Pressure Transient Analysis (PTA), deconvolution, nodal analysis, Rate Transient Analysis (RTA), and Flowing Material Balance (FMB) are extensively used to explain the reservoir behavior through PDA. It validates RTA and FMB as an approach for reservoir characterization and reserve estimation without the need to shut-in the well, and defer the production. The benefit of continuously monitoring Flowing Bottom Hole Pressure (FBHP) using Permanent Downhole Gauge (PDG) and applying deconvolution to detect well interference and reservoir boundaries is also discussed. We have also looked at the limitation and advantage of each method and how the integration of those can provide a full picture and enhance the results.
We have studied several gas fields. The results of analysis provided an accurate perception and understanding of reservoir behavior and characteristics, well interaction and interference, potential for infill wells, production issues and well constraints, estimation of the connected volume, and eventually led to generation of a reliable analytical reservoir model for the production forecast. The estimated connected volume was tested and proved to be reliable based on infill drilling. The workflow focuses on examining the data quality, confirming the validity of work, and achieving the maximum possible insight through integration of different analytical methods.
An integrated workflow is introduced for PDAand successfully applied on different cases of highly heterogeneous conventional gas reservoirs with huge complexities. The paper demonstrates one of the case study as example.
The proposed workflow shows to be very powerful particularly when large volume of data from pressure downhole gauges (PDG) is available. It saves significant time for the study team in determining the potential value of a project.
A mini drillstem test (DST) with a Wireline Formation Tester (WFT) tool was performed in a low-perm, unconsolidated gas reservoir in a shallow well in offshore Malaysia to obtain high quality gas samples and to determine main reservoir properties. Single probe WFT attempts were unsuccessful in the offset well because of tightness attributed to high silt content. Consequently, the mini-DST was run in open hole, rather than the normal full-bore DST, which was an option for reservoir characterization.
This paper describes a successful reservoir characterization using a mini-DST in an open hole in a shallow low permeability reservoir; it provides background information about the wireline formation tester jobs conducted in an offset well. The paper also addresses the design criteria for performing the mini-DST and delves into the factors that were considered for job planning and proper job performance.
The unconsolidated sand posed some challenges, including a significant risk of sand failure during pumpout. Conversely, the low permeability requires more drawdown to flow the tested interval. The paper also includes the steps undertaken to minimize this risk by analyzing real-time data.
Despite low permeability, a good radial flow was obtained and used to estimate reservoir properties by creating proper drawdown. The high mobility of the low pressure gas in the reservoir compensated for the reservoir tightness. Although the radius of investigation in a relatively short buildup is not sufficiently high, it can still assist in reservoir characterization for development purposes with the integration of core, petrophysical, and DST data.
The paper also demonstrates the contribution of proper job planning and real-time monitoring to overcome operational problems expected while performing mini DSTs in low permeability and unconsolidated reservoirs, and describes methods for addressing those problems.