Polymer injection in the south of Sultanate of Oman has been implemented in Marmul field for the last decade. Recently, alkaline surfactant polymer (ASP) technology has also been piloted in the field, which was technically successful owing to its significant incremental oil production. The current end-game strategy for the field is to follow polymer with ASP flood in order to produce the remaining oil after polymer flood and maximize the ultimate oil recovery factor. This has revealed the need for evaluation of the full-field performance of ASP flood using available tools. Full-field dynamic models are not always best tools for modeling the performance of chemical enhanced oil recovery, primarily due to under-representation of the reservoir heterogeneity, lack of the complementary data, complexity of the process itself, and large computation time. In this paper, we implement a conduit-model approach using field production data from the ASP pilot to assess the ultimate incremental oil recovery. This approach is compared to an analytical model that is based on the modified Koval’s method with reservoir heterogeneity as an input parameter. The obtained results are used for preliminary assessment of the difference between polymer and ASP injection in the full field.
The unexpected response of the Mauddud water flood project led to a detailed review of the petrophysical and geological aspects of this mature cretaceous carbonate reservoir. With almost 2,000 wells, more than 1,000 of which were recently drilled and three cored, the review assessed an extensive data base of openhole, production, saturation log, and historical geological data. The findings resulted in an improved understanding of this reservoir, which historically had been described both as homogenous - fractured and heterogeneous - layered. An understanding of Mauddud's key geological features, their formation, and a link to the observed petrophysics provided the key to developing an innovative permeability transform from resistivity logs, which explained the reservoirs response to the water flood project. With production permeability up to fifty times the measured matrix permeability from core, porosity log derived permeability had failed to reflect the fluid production observed. The adoption of a saturation and production based method provided a useable permeability profile that appeared to explain the observed well and pattern production behavior of the water flood. The new permeability profile also explained both historical fluid behavior and other Enhanced Oil Recovery (EOR) projects, and has since been universally adopted for the reservoir. The permeability estimation technique, which uses resistivity log data, was tested in another infield reservoir with success, and it is thought that the technique has general applicability across many Middle East carbonate reservoirs.
One of the North Kuwait Carbonate fields which starts its production in 1957 has very low recovery factor after 60 years of production although the field was under water flooding since 1997. A workflow was developed to first understand the reason behind the low recovery and second to propose the best way to improve it.
The workflow starts with first building a material balance model to understand the main reservoir driving mechanisms. Second, a fine-scale history matched simulation model was used to understand the main reasons of the current low recovery. A Produce High and Inject Low (PHIL) concept was proposed with locating all the injectors at the deepest zone and the producers at the shallow zones. Finally, the proposed PHIL concept with inverted 5-spot horizontal wells was examined compared to the inverted 9-spot vertical wells and to the peripheral PHIL concept using the simulation model to examine the best approach to maximize the recovery.
Different outcomes from the above-mentioned workflow can be summarized as follows; first, it was found that the main driving mechanism is water injection which represents 70% of the reservoir recovery factor. Hence the importance of creating an artificial aquifer along the whole area of the field to provide the required pressure support which calls for the implementation of the PHIL concept with inverted 5-spot pattern background as the best development concept for the field. Second, the thorough data review used on building the fine-scale model shows that the current recovery is dominated by single zone which represents only 15 % of the in-place and on top of this, it was found that all the developed wells are located only on 30% of the field leaving 70% of the field undeveloped. These are the main reasons behind the low recovery. Finally, the developed PHIL concept with inverted 5-spot background shows that the recovery can be increased by five times with less number of new wells and less water injection volume required compared to the 9-spot vertical wells and the peripheral PHIL concepts. This five-folds increase in recovery encourages the asset to do a pilot to implement the proposed development strategy.
Unlike the commonly used inverted 5-spot vertical wells, this work proposes a novel approach of inverted 5-spot horizontal wells with directing the horizontal injectors at the deepest zones and the horizontal producers at the shallow zones. Hence creating an artificial bottom aquifer with minimizing the water production and maximizing the water injection distribution along the whole area of the reservoir.
Ben Amor, Faical (Schlumberger Oilfield Eastern Limited) | Madhavan, Sethu (Kuwait Oil Company) | Edwards, Keith (Kuwait Oil Company) | Kalyanbrata, Datta (Kuwait Oil Company) | Filak, Jean Michel (Kuwait Oil Company)
A Cretaceous carbonate reservoir, deposited in a shoal complex environment, produced only 10% of the estimated STOIIP, yet currently suffering from a rapid reservoir pressure decline. Recently acquired geoscience and engineering data revealed a lot of subsurface uncertainties. To boost the production and support a pressure maintenance project, a reviewed reservoir evaluation was critical to narrow down the uncertainties on reservoir structure, Tarmat prediction, rock quality, oil distribution and connectivity of aquifer with neighboring fields.
Owing to lateral variation of depositional environments field-wise and a complex diagenetic processes history, mutli-scale heterogeneities are seen both vertically and areally. Capitalizing on limited dataset, collected from early development wells and previously overseen deep exploration wells, a fully integrated approach was required to address these heterogeneities. Fault data, integrated with log & pressure data analysis and seismically mappable Tarmat related flat spots enabled to decipher reservoir compartmentalization. Detailed property modeling used a hybrid hierarchical workflow of deterministic, statistical and stochastic techniques, and allowed capturing depositional/diagenetic rock quality variations, including seismically mappable Tarmats' overprint, calibrated with well and geochemical data.
At borehole-scale, a cascaded PCA-NNs methodology in a hierarchical order yielded the best results in predicting lithofacies at un-cored intervals using wireline logs, thus enabling more favorably the comparison with the benchmark charts than the clusters generated by directly using NN with the same original logs.
Starting from a statistically proven tight relationship between borehole lithofacies, reservoir rock types and porosity, well-calibrated inverted seismic porosity maps have been used in combination with their corresponding kriged lithofacies proportion maps, together with well/seismic based variography analysis and sedimentological/stratigraphical concepts, to generate lithofacies trend maps. Thesemaps will be the main input we used for 3D facies distribution at the field scale.
The quantification of lithofacies statistical correspondances between well and seismic inversion data, enabled to segregate between reservoir shoal facies (porous limestone), non-reservoir facies (tight limestone), and intermediate-quality facies (fine-grained packestone). Seismic-scale sedimentary/diagenetic bodies were explicitly integrated into the facies model, however high-resolution borehole facies were stochastically populated, through constraining them to pre-established lithofacies trend maps. This served to directly constrain the 3D porosity distribution and, in turn, reservoir rock types - integrating lithology, petrophysics and reservoir behavior - all closely linked to each other.
Kumaran, Prashanth Nair (PETRONAS Carigali Sdn Bhd) | Charbernaud, Thierry (Schlumberger) | Ibrahim, Ramli (PETRONAS Carigali Sdn Bhd) | Kadir, Zairi (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Yaakob, Mohd Taufiq (PETRONAS Carigali Sdn Bhd) | Mandal, Dipak (PETRONAS Carigali Sdn Bhd) | Ataei, Abdolrahim (PETRONAS Carigali Sdn Bhd) | Maldonado, Jorge (Schlumberger) | Abdul Rahman, Mohd Ramziemran (Schlumberger) | Iskenova, Gulnara (Schlumberger) | Ceccarelli, Tomaso Umberto (Schlumberger) | Djarkasih, Fredy (Schlumberger) | Abdul Rahman, Nor Nabilah (Schlumberger) | Mohd Salim, Ahmad Syahrir Hatta (Schlumberger) | Moreno, Juan Carlos (Schlumberger) | Cavallini, Alberto (Schlumberger)
A West Baram Delta prolific mature oil field has been developed through 150+ wells since 1975 in Malaysia. In 2015, an exploration well drilled in neighboring block, successfully found ~500ft TVT of gross oil, 50% less than expected due to structural changes. With lower than expected hydrocarbon in place, the project team was forced to re-evaluate the development and identified key strategies to minimize the number of wells to drill while ensuring healthy project economics. Optimizing reserves and ensuring future accessibility while minimizing number of wells and cost, were the key challenges. Rather than developing all sands with highly deviated well, the team designed an extended reach horizontal well targeting a single key reservoir containing 60% of block STOIIP. Team decided to drill from an existing platform with no pilot hole but opted for real time reservoir mapping technology for well placement. The well was designed with no smart completion due to surface power limitation. First time in the region a dual defensive sand control mechanism was selected, Gravel Pack & Sand Screens. The 1st ever horizontal well was drilled S field meeting its objective at Q4-2017 and exceeding forecasted initial rates. With a long horizontal open hole section and being the only well in the block, a major challenge was to delay water coning and to control water cut once water breaks through. This was achieved with the installation of 8 Inflow Control Devices (ICDs). Real-time reservoir mapping while drilling was used successfully to land the well and then optimize the production section in good quality sands despite structural uncertainty. The well, designed with 60° maximum inclinations, ensures routine well intervention to be done using slickline (i.e. gas lift valve change). Any major intervention would still require coil tubing with usage of barge. The horizontal profile overcomes the limitation of power supply for automation that would be faced with high angle deviated well hence saved significant surface modification cost. The out of box solution of optimized field development plan for complex offshore Brownfield with limited facilities modification, while being cost conscious but technically sound concept proven to provide the answer for sustainable production growth in S Field at low oil price environment. The success of this well has changed the team mindset to relook and propose similar design wells in previously deemed uneconomical FDPs within the S Field.
Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Kadir, Zairi (PETRONAS Carigali Sdn Bhd) | Kumaran, Prashanth Nair (PETRONAS Carigali Sdn Bhd) | Ibrahim, Ramli (PETRONAS Carigali Sdn Bhd) | Ahmad, Mior Yusni (PETRONAS Carigali Sdn Bhd) | Madon, Bahrom (PETRONAS Carigali Sdn Bhd) | A Aziz, Adam Hareezi (PETRONAS Carigali Sdn Bhd) | Ishak, Mohd Faizatulizuddin (PETRONAS Carigali Sdn Bhd) | Gordon Goh, Kim Fah (Schlumberger) | Ceccarelli, Tomaso Umberto (Schlumberger) | Tan, Chee Seong (Schlumberger) | Kalidas, Sanggeetha (Schlumberger) | Mohd Salim, Ahmad Syahrir Hatta (Schlumberger) | Maldonado, Jorge (Schlumberger) | Lei Min, Zhang (Schlumberger) | P Mosar, Nur Faizah (Schlumberger) | Gil, Joel (Schlumberger) | Abdul Rahman, Mohd Ramziemran (Schlumberger) | Watana, Kulapat (Schlumberger) | Chabernaud, Thierry (Schlumberger)
The first horizontal oil well was drilled through an anticline structure in the Block-7E of East Flank, S-field, penetrating three production sands Sand I, Sand II and Sand III. Based on a comprehensive pre-drill study through steady-state and 3D dynamic time lapse simulation, Inflow Control Device (ICD) with integral sleeve (on/off function) attached to the ICD's joint is the optimum development of the fault block that maximizes zonal control for contrasting water encroachments. Due to the unconsolidated nature of the target reservoir, this well is designed for Open-Hole Gravel Pack (OHGP) with specialty 3D filtration screen to manage sanding issue. This paper highlights 2-in-1 application of ICD with enabled zonal shut-off sleeves and the OHGP completions with external screen. A pre-drilled ICD dynamic modeling is constructed to evaluate the well performance with ICD configuration. The design criteria for an optimum ICD design configuration is based on number of compartments and size, packer placement, ICD nozzle sizes and numbers. This dynamic single well model was used to justify the technology value which resulted in production improvement (maximizing oil and minimizing/delaying water). However, during the drilling of this well, the pre-drilled model is then updated in real time with the input of actual petrophysical data from Logging While Drilling (LWD) measurements along the OH section. Actual well trajectory and structure adjustment encountered while drilling were also co-utilized to determine the final optimum ICD design for the field run-in-hole (RIH) completion. Target fault block in S-Field East Flank requires optimum development strategy for its economic viability (
Nagarkoti, Malvika (Baker Hughes, a GE company) | Pooniwala, Shahvir (Baker Hughes, a GE company) | Alam, Anwar (Baker Hughes, a GE company) | Anthony, Elred (Kuwait Oil Company) | Al-Othman, Mohammad (Kuwait Oil Company) | Aloun, Samir (Kuwait Oil Company) | Buhamad, Ali (Kuwait Oil Company) | Ashkanani, Meshari (Kuwait Oil Company)
Proppant fracturing treatments in sandstone formations are routinely executed in Kuwait, however when carbonate formations are the target, acid fracturing is the preferred treatment method. It has been observed that acid fracturing delivers a high initial production however maintaining a sustainable production rate is a challenge in the tight cretaceous carbonate formations in Kuwait. A production enhancement technique needed to be identified in order to deliver more sustainable production and maximize recovery from these carbonate formations.
Based on global experience it was proposed that proppant fracturing can deliver more sustainable production rate as compared to acid fracturing.
Proppant fracturing had been previously attempted on two occasions in Kuwait, however both the attempts were evaluated as not being operationally successful. Hence prior to executing the first successful proppant fracturing treatment in carbonates in Kuwait a thorough study was undertaken to identify and mitigate the possible risks.
The cretaceous carbonate formations in North Kuwait are relatively shallow and are known to be tight and highly ductile. Due to the ductility of these formations, proppant placement and reduction of the fracture conductivity due proppant embedment were thought to be significant risks. During the course of the project, detailed core analysis and testing was conducted using formation core samples to ascertain the severity of this risk.
Successful execution of this hydraulic fracturing treatment was pivotal in order to plan the future production strategies from these formations. A cautious approach needed to be followed as proppant placement was of paramount importance. Different strategies were incorporated in the fracturing workflow to ensure the success of the treatment and to maximize data collection in order to optimize future treatments and well placement. Multiple mini-fracs, temperature logs and pumping of novel non-radioactive tracer proppant were some of the techniques utilized.
During execution various decisions were taken real-time to ensure success of the treatment. It was observed that all parameters were consistent with the results of the core and laboratory testing conducted during the initial phase of the project which lead to optimizing the proppant placement.
The success of this treatment has been a game changer resulting in more wells being identified as candidates for proppant fracturing in this field.
Now that proppant placement has been established the objective of future treatments is to optimize fracture designs, fluids and treatment schedules which will help the future production enhancement strategy for this field.
Lessons learnt from this first successful well will be applied to future wells planned in carbonate reservoirs in Kuwait, in order to maximize recovery.
Kumaran, Prashanth (PETRONAS) | Mandal, Dipak (PETRONAS) | Kadir, Zairi (PETRONAS) | Kamat, Dahlila (PETRONAS) | Ibrahim, Ramli (PETRONAS) | Maldonado, Jorge (Schlumberger) | Iskenova, Gulnara (Schlumberger) | Sharma, Sachin K. (Schlumberger) | Rahman, Mohd Ramziemran Abdul (Schlumberger) | Chabernaud, Thierry (Schlumberger) | Ceccarelli, Tomaso (Schlumberger) | Syahir, Ahmad (Schlumberger) | Djarkasih, Fredy (Schlumberger) | Rahman, Nor Nabilah Abdul (Schlumberger) | Moreno, Juan Carlos (Schlumberger)
In the current period of industry downturn, creating and executing opportunities to develop an offshore brownfield has become more economically challenging. This paper describes the technical, commercial, and operational aspects that helped in achieving an established economical cut-off for project sanction. The project will enable sustaining field average oil production above operational economic limits thereby maximizing field life. With the prevalent low oil price conditions, the economic threshold for projects sanction and execution has reduced. The asset team faced a challenge to achieve a UDC threshold of USD16/bbl. Multi-disciplinary team was tasked to look at key aspects to improve project commerciality. Subsurface recovery potential was assessed thoroughly to evaluate the impact of subsurface uncertainty, and evaluate the impact on well designs on the project cash flow. Wells were designed to tap multiple reservoir targets to minimize subsurface risk through existing facilities to maximize ullage. The wells were drilled from new slots via small deck extension instead of the high-risk slot recovery option, which helped to reduce the Capital Expenditure (CAPEX). Fit-for-purpose and cost optimized wells were designed by minimizing automation (i.e.: ICVs, PDGs, etc.) which also reduced operating risk and cost. Multiple sands were targeted in different compartments with different pressure system, hence planned not to commingle production. Hence, only one primary reservoir was completed, with other zones kept behind casing for future intervention with bottom-up production strategy. This helped deferring the project investment as this was in the intervention cost in Operating Expenditure (OPEX) which helped to improve the project economics. Further cost savings were achieved by accelerating the project in order to achieve synergy with an upcoming drilling campaign. The reduction of the overall project CAPEX, thus allowed the project to be commercially feasible and technically sound for execution. In addition, the team has also established a reservoir management plan with mitigation plan to deal with the main subsurface and surface risks. The out of box solution of optimized field development plan for complex offshore brownfield with limited facilities modification, while being cost conscious but still ensuring technically sound concept proved to provide the answer for sustainable production growth in S Field at low oil price environment. This paper will also highlight the key lessons learnt and obstacles which were observed during the execution of the project are expected to become guidelines for future low cost projects in this region.
Carbon dioxide injection has recently been considered as a promising method for enhanced oil recovery. The supercritical carbon dioxide is often miscible or nearly miscible with the oil under reservoir conditions, which facilitates high recovery. Underground injection of carbon dioxide is also of a significant ecological advantage, and utilization of CO2 results in a noticeable reduction of the taxation of the petroleum companies. On the other hand, application of carbon dioxide under conditions of the North Sea petroleum reservoirs for enhanced oil recovery (EOR) is hindered by multiple practical problems: availability of the CO2 sources, logistics of the delivery offshore, corrosion resistivity of the installations, and other. Previous studies of CO2 EOR for the reservoirs of the North Sea region, including core-flooding experiments and reservoir simulations, indicate that the deployment of CO2-EOR can significantly enhance the recovery of hydrocarbons. However, CO2 must be generated from anthropogenic sources, which affects the feasibility of the projects.
The current study evaluates the potential of a CO2-EOR project under the conditions of a specific petroleum reservoir of the Danish sector North Sea. Geological characteristics of the reservoir and the detailed oil properties lie in the ground of the study. The minimum miscibility pressures between CO2 and the reservoir oil are evaluated with the help of the in-house software (SPECS 5.70) and the commercial reservoir simulator (ECLIPSE 300). The results are verified in the slimtube simulations. The effect of the different oil characterizations and its lumping into the different numbers of components is investigated. The oil is found to be miscible with the carbon dioxide under reservoir conditions.
Several injection scenarios have been tested on the 2-D and 3-D reservoir models. Waterflooding was compared to injection of carbon dioxide, as well as water-alternate gas injection. An optimal scenario with regard to water-gas ratio under WAG was selected for further studies.
Finally, a cash flow model by Monte Carlo simulations and a sensitivity analysis on the impact of oil and CO2 price and discount rate, certify the feasibility and attractiveness of a CO2-EOR project in the West Flank of the Dan field.
This paper develops innovative methods for analysis of some important exploration and production problems in shale petroleum reservoirs such as the determination of burial maturity and maturation trajectories, and determination of sweet spots with the use of Modified Pickett plots. The methods are explained with data from 226 Niobrara wells.
Pickett plots have been used historically as a powerful tool for petrophysical analysis of well logs. The plots represent a snapshot on time that corresponds to the time when the well logs are run. Pickett plots rely on pattern recognition observable on log-log crossplots of porosity vs. true resistivity. The analysis has been used in the past primarily for determination of water saturation. However, the plot has been extended throughout the years for evaluation of other parameters of practical importance including, for example, permeability, process or delivery speed (permeability over porosity,
In this paper, Pickett plots are extended from representing a snapshot on time to representing millions of years of burial and maturation trajectories. The proposed method is explained with data from 226 Niobrara wells. The modified Pickett plots leads to curved lines of water saturation (Sw) and BVW. The maturation trajectories on the plot help to explain compaction and why as maturation increases to generate oil and gas condensate, resistivity goes up. However, as maturation increases to generate dry gas in the Niobrara, resistivity decreases. The Lopatin time-temperature index (TTI) is also included in the modified Pickett plot.
The proposed methodology also allows estimating changes in pore throat sizes updip and downdip of a structure, as well as in a basin flank. The ability to combine maturity, pore throat sizes, as well as porosity and process speed in a single graph makes the modified picket plot a valuable tool with potential to locate sweet spots in shale petroleum reservoirs to locate areas for possible improved oil recovery (IOR) and enhanced oil recovery (EOR).
The key contributions of this paper are generating an original method for determining burial maturity and maturation trajectories of shale petroleum reservoirs with the use of modified Pickett plots, as well as determining changes in pore throat sizes in different places of a structure, which lead to the location of sweet spots. Although the methodology is explained with data of the Niobrara shales, it should have application in other shale petroleum reservoirs of the world.