Gong, Jiakun (Delft University of Technology) | Vincent-Bonnieu, Sebastien (Shell Global Solutions International B.V.) | Kamarul Bahrim, Ridhwan Zhafri (Petronas) | Che Mamat, Che Abdul Nasser Bakri (Petronas) | Tewari, Raj Deo (Petronas) | Groenenboom, Jeroen (Shell Global Solutions International B.V.) | Farajzadeh, Rouhollah (Delft University of Technology and Shell Global Solutions International B.V.) | Rossen, William R. (Delft University of Technology)
Surfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity.
In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator’s results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor.
The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.
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.
Uli, D. A. (PETRONAS Carigali Sdn. Bhd.) | Mithani, A. H. (PETRONAS Carigali Sdn. Bhd.) | Ali, Kartina (PETRONAS Carigali Sdn. Bhd.) | Abu Mansur, Roslan B (PETRONAS Carigali Sdn. Bhd.) | Masoudi, Rahim (PETRONAS Carigali Sdn. Bhd.) | Tewari, Raj Deo (PETRONAS Carigali Sdn. Bhd.) | Jirim, Shamsudin (PETRONAS Carigali Sdn. Bhd.) | Harith, Z. Z. T. (Beicip Technology Solutions) | Mohammad, M. H. H. (Beicip Technology Solutions) | Kanesan, T. (Beicip Technology Solutions) | Kolupaev, A. (Beicip Technology Solutions) | Lee, Y. (Beicip Technology Solutions)
The paper discusses an innovative methodology of designing a carbonate reservoir model on a field in Central Luconia for planning further optimal field development and reservoir management & surveillance (RMS) using a Forward Stratigraphic Modelling (FSM) approach. Understanding of carbonate reservoir architecture is important for successful, stable hydrocarbon production and reservoir management plan. This understanding on early stages can help to prevent unpredictably low productivity & recovery, early water breakthrough and design field-customized RMS formulation.
Complex depositional and diagenetic facies distributions in carbonate reservoir are the main challenges for development and production of hydrocarbon from carbonate fields worldwide. They are often naturally unique geologically, and exhibit complex porosity systems and permeability characteristics, which drastically influence whole cycle of reservoir management and surveillance. Geostatistical approach is often unable to capture the geological heterogeneity which leads to oversimplification of the carbonate reservoir model. Many uncertainties would be present in forecasted hydrocarbon and water production, volume in place and reserves estimation, optimal well design and locations, which effects the whole Field Development Strategy. This further becomes a challenging task in high mobility fluids like gas of Central Luconia with 90% of gas production in Central Luconia beingfrom Carbonate Reservoirs. With the complexity of the carbonate characteristics and its uncertainties, it is crucial for PETRONAS to reinvent its approach towards managing carbonate field and embrace the new ideas beyond those normal practices.
By years of research and development of numerical computer simulations, FSM has proved to be a complementary alternative process-based approach to create a better carbonate reservoir model which is geologically realistic and obeys stratigraphic principles.
The method used in the FSM approach is to first set the modelling input parameters which mostly represents the main depositional processes such as conditions of wave energy & direction, paleobathymetry, carbonate production rate, eustatic changes, amount of subsidence etc. These input parameters are obtained from an integrated approach of analysis on all hard data available including understanding of modern analogues to create a conceptual model at time of deposition. Once these input parameters have been identified, the simulation is computed to provide a first-pass model which is validated with hard data. If present mismatch, the input parameters will be tweaked and another simulation is computed. The steps are repeated until an acceptable match between the model results and the hard data is obtained.
There will be numerous uncertainties available as many different input parameters may still provide different model results which matches the existing hard data available. Thus, a sensitivity and uncertainty analysis is computed to understand the most influential input parameters for creation of the reservoir model and also provide multiple model realizations which best represents the available hard data.FSM uncertainties are combined with G&G and dynamic uncertainties to have a robust model which can guide a formulation of optimal development and RMS planning.The innovative workflow applied at field scale allowed the modelling of highly heterogeneous, complex carbonate field which honours core, well logs, and seismic data.The application of this workflow honouring core, well logs, and seismic data as an alternative to conventional stochastic methodologies help to prevent field problems related to heterogeneity mis-modelling (simplification) in future such as unpredicted fast water breakthrough, reserves under/overestimation, field underperformance and help in the formulation and development of reservoir management strategies plan.
Kechut, Nor Idah (Petronas) | Hassan, Abd Azim (Petronas) | Izyan, Wan Fatin (Petronas) | Zamri, W M (Petronas) | Raub, Mohd Razib A (Petronas) | Tewari, Raj Deo (Petronas) | Kuzmichev, Dmitry N. (LEAP Energy) | Mironenko, Yulia (LEAP Energy) | Buoy, Rina (LEAP Energy) | Alessio, Laurent D. (LEAP Energy)
In stacked reservoirs with commingled production, achieving an understanding of relative contributions of the flow units is fundamental to reservoir management, most notably for conformance management of reservoirs under water flood or enhanced oil recovery (EOR) scheme. To that effect, the desired surveillance data usually includes: reservoir layer pressures, phase distribution profiles (through PLTs) in flow units, and monthly well test data (water cut, gas oil ratio, oil rate etc.). These measurements will form the basis of well by well flow unit production allocation; all necessary information for classical engineering analysis and reservoir simulation. The enduring challenge of value-effective reservoir management is to determine the'adequate' frequency and selection of well and flow units data acquisition. Industry practice shows clearly that there is no consistent answer to this challenge. In the authors' opinion, this is due to the unavailability of a methodology and tools to rigorously define the Value of Information (VOI) associated with surveillance data acquisition. VOI is defined as the net present value (NPV) difference between the total production & costs outcomes with the benefit of information, and the total production & costs outcomes without this information. In some cases, the VOI can also indirectly translate to critical understanding of subsurface integrity such as unintentional communication of deeper, higher pressure gas reservoir with shallower reservoir units having a much lower fracture gradient that if left unattended could subsequently lead to subsurface blowout scenario.
Khanifar, Ahmad (EOR Program, Technical Global, PETRONAS) | Raub, Mohd Razib Abd (EOR Program, Technical Global, PETRONAS) | Tewari, Raj Deo (EOR Program, Technical Global, PETRONAS) | Zain, Zahidah M (EOR Program, Technical Global, PETRONAS) | Sedaralit, M Faizal (EOR Program, Technical Global, PETRONAS)
Average recovery factor in offshore field under discussion is relatively moderate due to wider well spacing and poor sweeping efficiency thus leaving significant volume of oil behind in the reservoir. Timely application of EOR is therefore necessary to enhance the recovery factor to a reasonable level. Among the various EOR processes and techniques of EOR screened, studies found immiscible water-alternating gas (IWAG) injection as the most suitable and viable option for this Malaysian mature offshore oilfield. Realistic estimate of incremental oil by EOR is paramount as IWAG application involves high CAPEX and OPEX project. Therefore, representative is required to be generated in the laboratory for constructing a realistic reservoir simulation model to understand the three phase flow in porous media and support the IWAG process for full field implementation. Important parameters in this case are residual oil saturations in sequential injection of displacing fluids water and gas and trapping of gas, injection volumes and frequency of alteration. Therefore, IWAG core flooding experiments under reservoir conditions need to be performed, results quantified and parameters for hysteresis modeling established.
This paper addresses the challenges and strategies of IWAG core flooding experiment performed under reservoir conditions using representative composite native cores, live reservoir oil sample, field produced gas sample and synthetic formation brine water. The laboratory injection rates are considered equivalent to the field fluid advance velocity like in any standard displacement steps. Also, gravity stable injection mode is considered to achieve the best IWAG displacement performance. These challenges and strategies are drawn from lessons learned during accomplishment from earlier IWAG core flooding experiments. The IWAG core flooding experiments were performed on composite field core samples, arranged according to Langaas method, using current field production gas with 60 mole % CO2. The composite reservoir core samples were initially saturated with live oil and irreducible formation water and then flooded with formation water and seawater to residual oil saturation at reservoir conditions. Following, waterflooding, a number of water and gas cycle slugs were injected. The displacements were conducted at pressures well below the estimated minimum miscibility pressure during these experiments. Laboratory studies and numerical simulation study conducted on the applicability of immiscible WAG injection using high CO2 content produced gas indicated that 7.0 % additional oil recovery over waterflooding period can be recovered.
Kittrell, Charles (Schlumberger) | Sessarego, Horacio (Schlumberger) | Tewari, Raj Deo (PETRONAS) | Othman, Tg Rasidi Tg (PETRONAS) | Yeomans, Hugh G. (PETRONAS) | Taslim, Gunawan (PETRONAS) | Djohor, Mohamed (Schlumberger) | Bahraie, Ramin (Schlumberger) | Meyer, Juergen (Schlumberger) | Jiang, Long (Schlumberger) | Whitney, Patricio (Schlumberger) | Enriquez, Hugo A. Costeno (Schlumberger) | Kiome, Patrick (Schlumberger) | Montero, Alfonso R. (Schlumberger)
The Late Neogene Baram Delta province developed on an active margin located offshore Borneo in Malaysia. The field has been in production since 1982, and a total of 64 wells have been drilled from three (3) platforms. This paper discusses the process used to locate remaining oil for infill drilling. This involved a multidisciplinary effort including geology and geophysics, reservoir engineering, drilling / completion, and production technology.
The geologic and geophysical (G&G) assessment consisted of updating the static model and constructing mobile oil thickness and structural and bubble maps of all reservoirs. These maps were used in conjunction with original and current fluid contacts and helped to identify and locate remaining oil accumulations. The target portfolio was screened and ranked, and preliminary wellbore paths were built. Four (4) new wells and eight (8) sidetracks combining either shallow or deep targets were passed on to the reservoir engineering team for optimisation from simulation models and first-pass estimation of oil incremental reserves.
Reservoir simulation focuses on optimising target intervals as determined through G&G work and drilling design. Well constraints are set to be consistent with operating field production practices and facilities constraints. Completion intervals for the dual-string wells are optimized to minimise water cut and maximise oil rates. All simulation results are rigorously checked against offset well production and observed properties.
Once drilling targets are risk-assessed on the basis of structural, fluid contacts, and properties uncertainties, the final well trajectories are designed by the drilling team.
This study identified and ranked multiple undrained and appraisal areas. A full infill redevelopment consisting of more than 10 accelerated wells planned through the utilisation of existing facilities was presented and approved by PETRONAS Carigali Sdn. Bhd. (PCSB). The well and target portfolio is focused on three (3) main field development areas: Attic oil in shallow Pliocene reservoirs New development areas in deeper Miocene levels on the southern block Untapped deep Miocene reservoirs on the northeastern flank in crestal location
Attic oil in shallow Pliocene reservoirs
New development areas in deeper Miocene levels on the southern block
Untapped deep Miocene reservoirs on the northeastern flank in crestal location
The first two (2) sidetracks and three (3) workovers were successfully completed in December 2012, and the current oil production is 40% higher than originally estimated. The successes to date have proved the effectiveness of the concepts that were applied to identify and develop the remaining oil, and the field became East Malaysia's top producer.
The expected worldwide average recovery factor is around 35% with current development strategies and practices in place. Recoveries in the offshore fields are much lower compared to onshore fields predominantly due to larger well spacing, inadequate reservoir characterisation and shorter life cycles. Efforts are in place to maximise recovery by applying Enhanced Oil Recovery (EOR) techniques. Reservoir rocks saturated with hydrocarbons are complex in both a macroscopic and microscopic scale and this complexity controls the initial quantity and distribution of hydrocarbons and flow behaviour of fluids within the reservoir. Therefore, reservoir characterisation is of utmost importance for the evaluation process in EOR. Core and log analysis along with pressure-production data greatly assist in defining the reservoir and reducing the uncertainties associated with it.
This paper discusses the importance and criticality of core analysis starting from core acquisition, preservation, laboratory studies, analysis to the application of data. Discussions are conducted for the selection of the most appropriate coring technique while lab studies were carried out on cores for reservoir description, estimation of EOR incremental oil and formation damage during injection and production processes. Critical analysis is made to highlight the quality and quantity of core analysis data needed for petrophysical interpretation, understanding the storage and flow behavior during primary, secondary and tertiary recovery stages. Important guidelines are also provided for the selection of number of plug samples for studies, laboratory methodologies, their strengths and weaknesses, and Quality Control (QC)/Quality Assurance (QA) techniques.
The paper further elaborates the recent advances in EOR processes particularly on core analysis, in-situ saturation monitoring, and the interaction between injectants and rock-fluid along with mitigation experiments. Digital core/Pore network modeling is one such emerging technique utilised for the visualisation, characterisation and special core analysis (SCAL) measurements of reservoir rocks. It can provide routine and special core analysis measurements and petrographic analysis which can be used in the quick evaluation of static and dynamic petrophysical properties and flow behavior.
Tewari, Raj Deo (Petronas) | Abd Raub, Mohd Razib B. (Petronas) | Zain, Zahidah Md (Petronas) | Chien, Chee Sheau (Petronas) | Wan Mohd Zainudin, Wan Nur Safawati (Petronas) | Costier, Laurent (Sarawak Shell Berhad) | Chekani, Mitra (Petronas)
Economically achievable oil recovery factors for offshore fields are typically lower than for similar onshore fields due to larger well spacing, inadequate reservoir characterization and shorter economic field life. The key challenge for mature offshore field development is to leverage on surface and subsurface assets by progressively evaluating field redevelopment opportunities and executing phased projects to mitigate risks. Applying appropriate EOR techniques will help to maximize economic oil recovery and tap the relatively large remaining oil volumes in these offshore mature fields. In addition, the synergies among "making the most of what you have" (facilities rejuvenation, asset integrity, production optimization and production enhancement), infill drilling campaigns, implementation of water and/or gas injection schemes and the design/execution of EOR field development schemes are critical success factors. These highly integrated and risk-based field redevelopment planning efforts have gained momentum worldwide and this paper describes the learnings from a mature oil field offshore Malaysia.
For the field under discussion, the current (primary) field development strategy of simultaneous production from multiple stacked reservoirs and continuous optimization of artificial lift will lead to modest oil recovery (30 to 35% average oil recovery factor). After more than 30 years on production and multiple previous infill drilling campaigns, the number of available drilling slots on the offshore platforms is limited, plus there are challenges in reaching attractive bypassed oil targets from existing platform/well locations. New well head platforms and intra-field pipelines are expensive, so the existing well drainage plan is compromised in terms of the number and location of production wells.
To achieve the desired step up in economic oil recovery, a field redevelopment plan is required that logically combines various risk-based strategies and value adding components. This paper describes the range of subsurface and field development studies that were required to define an effective field redevelopment plan including EOR (iWAG). Realizing an offshore EOR project with an attractive and robust unit development cost is challenging, especially in the current environment of softening oil prices. This paper also discusses the strategies of defining a field redevelopment plan in this mature oil field through integration/synergy between efforts to safeguard the NFA production (No Further Activity) and additional infill combined with realization of iWAG. It is fully understood that the timing of development project implementation is important for economic value and that it would normally not be prudent to exhaust primary and secondary development options before embarking on tertiary EOR techniques, but a synergistic and risk-mitigation (phased) approach is necessary in these high cost, mature offshore field environments.
Khanifar, Ahmad (Technology, EOR Program, Technical Global, PETRONAS) | Abd Raub, Mohd Razib (Technology, EOR Program, Technical Global, PETRONAS) | Tewari, Raj Deo (Technology, EOR Program, Technical Global, PETRONAS) | Zain, Zahidah M (Technology, EOR Program, Technical Global, PETRONAS) | Sedaralit, M Faizal (Technology, EOR Program, Technical Global, PETRONAS)
Among various Enhanced Oil Recovery (EOR) processes and techniques, Malaysia's matured offshore oilfield which is currently under water injection for pressure maintenance appears to be amenable to water alternating gas (WAG) implementation. EOR screening studies show that WAG EOR application is ranked high among other EOR techniques and stands better chance of success techno-economically.
This paper addresses the immiscible water alternating gas (IWAG) core flooding experiments which were conducted to further investigate and to validate the efficiency of IWAG as a viable EOR technique in one of the highly-faulted, multi-stack reservoirs offshore Malaysia. The IWAG coreflooding experiments were performed on field core composites using current field production gas which has more than 60 % mole CO2. The composite core samples were initially saturated with live oil and irreducible formation water and then flooded with formation water to residual oil saturation at reservoir conditions. Following waterflooding, a number of WAG cycle slugs were injected. The displacements were conducted at pressures well below the estimated minimum miscibility pressure during these experiments.
The coreflood experimental results show that the IWAG injection has a potential to recover up to 7.0 % additional oil recovery over waterflooding. Injection fluids are sea water and CO2 rich produced hydrocarbon gas. Furthermore, almost 2.0 % of this incremental oil recovery can be attributed mostly to the hysteresis effects from IWAG process. In conclusion, the results of this laboratory IWAG project has provided the pertinent data required for constructing a reservoir simulation prediction model under IWAG process. Instead of the conventional drainage-imbibition curves input, WAGHYSTER parameters established from IWAG coreflood matching has been used for IWAG prediction evaluation and optimization scenarios for full-field scale implementation. Despite the limited available laboratory data which was based on certain rock properties, the history-matched numerical IWAG coreflood model and the established parameters such as Land's parameter, secondary drainage reduction factor and residual oil modification fraction forms the basis of input to further evaluate the sensitivity of these parameters on IWAG full-field implementation.
Zulhaimi, Muhammad Jazlan (EORC) | S. Wan Ibrahim, Wan Mohd (EORC) | Sanyal, Satyashis (EORC) | Zamri, Khairul Azhar (EORC) | Mohamad, Muhammad Naim (EORC) | M Zaini, Khairul Nizam (EORC) | Tewari, Raj Deo (PETRONAS Carigali Sdn. Bhd.) | Pradhan, Akshaya Kumar (PETRONAS Carigali Sdn. Bhd.)
The matured field is located in the Sarawak offshore, Malaysia. Discovered in 1968, the field is an anticlinal structure with vertically stacked reservoirs deposited in a shoreface environment. The brown field has been producing under active aquifer drive with a very high recovery factor. The field is currently producing with more than 85% WC and has significant levels of uncertainties with respect to oil-water contacts, flank structure, depth of spill points, production allocation, SCAL and residual oil saturation.
Major challenges were observed in building fine static models for further dynamic simulation work. A coarse mega model were built covering all reservoirs to capture the STOIIP uncertainties in the field as well as to support an integrated conventional approach to locate the remaining oil and estimating the potential infill reserves. A robust workflow were developed to identify the infill opportunities by integrating material balance study, case hole logs information, water diagnostic plots, decline curve analysis and many more. The comprehensive LTRO methodologies applied has been successful in identifying the location of the remaining oil as well as estimating the potential reserve. This approach has also managed to accelerate field development plan and afforded the team efficient resource optimization by avoiding the more time consuming re-cycling the conventional static-dynamic modeling approach.
The field is located 20 km offshore Sarawak in water depths of 100 ft. The field, which was discovered in May 1968, fell under the BDO PSC, which was to expire on 31stMarch 2018. A new EOR PSC was signed on 16thJanuary 2012, which extends the expiry date to 2040.
The field structure consists of a 30,000 by 9,000 ft elongated anticline running NE-SW and comprises a series of stacked reservoirs at a depth of 4000 to 9500 ft. The field is considered structurally simple, with a normal growth fault affecting only the deep reservoirs and no other faults visible on 2D seismic or in the wells.
The field reservoirs were deposited some 20-23 million years ago during Cycle V of the late Miocene in a lower coastal plain to coastal environment. The depositional environment of this field is dominated by a sequence of shore-face deposits, which formed 6-11 million years ago during Cycle V of the late Miocene.
Sands are loosely consolidated, fine to very fine grained and interbedded with layers of silts and clays. Porosity ranges from 14 to 26 % with a field-wide mean of 20%. The permeabilities are in the order of 50 to 3000mD. Net sand thicknesses are less than 30 ft, with most individual sands around 10 ft. The reservoirs are subdivided into three categories (Figure 1):
Shallow Reservoirs at depths of 4000 to 5300 ft, which are characterized by large gas caps and mostly thin oil rims, and are currently considered unfaulted.