Bottom hole pressures are valuable source of information for reservoir surveillance and management and are the heart of reservoir engineering. Real – time pressure measurements record pressure data at 5 second interval resulting in enormous accumulation of data. The size and volume of the accumulated data limit the capability of existing analysis software to load and interpret data. This paper presents an improved methodology for data quality checking and data optimization in determining reservoir pressure depletion via Autoregressive Integrated Moving Average (ARIMA) and Decision Tree Model.
Dataset was gathered from a representative reservoir from Malay Basin. The ARIMA algorithm presented was designed for quick and efficient data quality checking. The Decision Tree Model in other hand was utilized to select maximum buildup pressure for reservoir depletion point via well status parameters. The maximum pressures were selected from buildup up data when the decision tree conditions were met. Versus classical methods, the algorithm has obtained around 90% similarity. The resulting data were then can fully optimized for reserve reporting and forecasting study i.e. analysis and numerical simulation.
The paper also reports on the advantages in the application of ARIMA – Decision Tree Algorithm in pressure surveillance revealing few key advantages namely minimize the need of well intervention and optimized workflow for reservoir engineer to view, utilize, and detect reservoir depletion data. ARIMA – Decision Tree Algorithm is targeted to be installed and integrated in field historian for better overall data analysis and visualization. Results produced from the ARIMA – Decision Tree Algorithm which consist of reservoir pressure depletion data will then improve more advance analysis such as simulation and forecasting in terms of overall speed and accuracy.
As a conclusion, this paper presents the importance and application of incorporating Big Data Analytics Algorithm in reservoir management and reporting. Future work, deliverability calculations can be incorporated in the model to identify and rectify any abnormal reservoir behavior.
Ahmed, Shehzad (Universiti Teknologi PETRONAS) | Elraies, Khaled Abdalla (Universiti Teknologi PETRONAS) | Hanamertani, Alvinda Sri (University of Wyoming) | Hashmet, Muhammad Rehan (Nazarbayev University) | Shafian, Siti Rohaida Mohd (PETRONAS Research Sdn Bhd) | Hsia, Ivy Chai Ching (PETRONAS Research Sdn Bhd)
The application of CO2 foam has caught overwhelming attention for fracturing shales. In applications, high foam deterioration and insufficient viscosity at operating conditions are the major concerns associated with foam fracturing process. In this study, polymer-free CO2 foam possessing high stability has been presented through chemical screening and optimization under HPHT conditions. Initial screening was performed by conducting a series of foam stability experiments considering different commercial anionic surfactants, concentration, and foam stabilizer addition using FoamScan instrument. Foam rheology study was then performed by considering the similar investigated factors under fracturing conditions using HTHP foam rheometer. All the tested solutions were prepared in fixed brine salinity and HPAM polymers with different molecular weights were used in evaluation of the performance of the designed polymer-free foam in term of foam strength. In comparison with other types of surfactant, alpha olefin sulfonate (AOS) exhibited the best foam stability and viscosity at testing conditions. The optimum AOS concentration providing the best performance was found to be 5000 ppm and its combination with 5000 ppm of foam booster (betaine) further increased AOS foam longevity. An improved result on foam stability and viscosity was not obtained by increasing surfactant concentration. Results on foam rheology reveals that CO2 foam generated in the presence of different molecular weight classical HPAM polymers could not provide significant increment in foam viscosity under experimental conditions. It was observed that these types of polymer underwent degradation due to some unfavorable mechanisms which will be expected to negatively affect its performance during fracturing process. On the other hand, polymer-free CO2 foam was found to produce a higher stability and relatively equally high viscosity compared to polymer-stabilied CO2 foam without experiencing degradation at high pressure and temperature conditions. Therefore, based on this study, it is recommended to use polymer-free foam for fracturing shales application. The use of formulated polymer-free CO2 foam which has high stability and viscosity will lead to improved fracture cleanup, minimized formation damage and pore plugging, and efficient proppant placement which will ultimately enhance gas recovery from unconventional shales.
Md Jalil, Abdullah Al Mubarak (PETRONAS Research Sdn Bhd) | Mat Isa, M Faudzi (PETRONAS Research Sdn Bhd) | Rostani, Khairul (PETRONAS Research Sdn Bhd) | Othman, Nurzatil Aqmar (PETRONAS Research Sdn Bhd) | M Shariff, Azmi (Universiti Teknologi PETRONAS) | Lau, Kok Keong (Universiti Teknologi PETRONAS) | Partoon, Behzad (Universiti Teknologi PETRONAS) | Tay, Wee Horng (Universiti Teknologi PETRONAS)
As easy gas resources around the world are depleting; high Carbon Dioxide (CO2) gas fields are thrust into the spotlight to become new candidates for field development. However, the presence of oftentimes sizable Carbon Dioxide contents in the gas reservoir (can be up to 80% volumetric) introduced a huge technical and economic challenges towards the field exploitation.
Over the last few years, several studies have been conducted on cryogenic technologies such as cryogenic distillation and supersonic nozzle in CO2 separation for fields containing more than 40% of CO2. Based on the studies, these new cryogenic technologies have shown to have high potential in separating CO2 from natural gas offshore to be utilized under carbon, capture, storage and utilization (CCUS) project.
The new cryogenic technologies are currently being tested for the proof of concept. Hence, a pilot plant, which is a scaled down version of the technology was developed. One of the major challenges faced during the pilot plant testing is the emergency depressurization philosophy as the process involves CO2 solids handling which is uncommon to the industry standard. Depressurization of high CO2 fluid at cryogenic temperature would lead to possibility of CO2 solids formation, hence potential blockage of process equipment and venting line.
Therefore, this paper will focus on the design of the pressure relieving system of such a facilities. It would also touched on the implementation of the pressure relieving system during the operation of the pilot tests and as well as the tests designed specially to test the pressure relieving system. Finally the paper would give a few proposals on improvements to be made to such system. It is also the ultimate aim of the authors and the team to introduce a new philosophy for Cryogenic CO2 Blowdown system to the process industry.
Shah, Swej (Delft University of technology) | As Syukri, Herru (Delft University of technology) | Wolf, Karl-Heinz (Delft University of technology) | Pilus, Rashidah (Universiti Teknologi PETRONAS) | Rossen, William (Delft University of technology)
Foam reduces gas mobility and can help improve sweep efficiency in an enhanced oil recovery process. For the latter, long-distance foam propagation is crucial. In porous media, strong foam generation requires that local pressure gradient exceeds a critical value (∇Pmin). Normally, this only happens in the near-well region. Away from wells, these requirements may not be met, and foam propagation is uncertain.
It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability (
This article is an extension of a recent study (
Local pressure measurements and CT-based saturation maps confirm that foam is generated at the permeability transition, which then propagates downstream to the outlet of the core. A significant reduction in gas mobility is observed, even at low superficial velocities, however, the limit of foam propagation is reached at the lowest velocity tested. CT images were used to quantify the accumulation of liquid near the permeability jump, causing local capillary pressure to fall below the critical capillary pressure required for snap-off. This leads to foam generation by snap-off. At the tested fractional flows, no clear trend was observed between foam strength and fg. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous work (Rossen, 1999). Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate - probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and increasing fractional flow. Within the range of conditions tested, the onset of foam generation (identified by the rise in ∇P and Sg) occurs after roughly the same amount of surfactant injection, independent of fractional flow or injected rate.
Bashir, Yasir (Universiti Teknologi PETRONAS) | Babasafari, Amir Abbas (Universiti Teknologi PETRONAS) | Biswas, Ajay (Universiti Teknologi PETRONAS) | Hamidi, Rositi (Universiti Teknologi PETRONAS) | Moussavi Alashloo, Seyed Yaser (Universiti Teknologi PETRONAS) | Tariq Janjuah, Hammad (American University of Beirut) | Prasad Ghosh, Deva (Universiti Teknologi PETRONAS) | Weng Sum, Chow (Universiti Teknologi PETRONAS)
A majority of remaining proven Oil & Gas reserves is contained by Carbonate reservoir, and much more complicated to explore as imaging of the Carbonate rocks is poor. In case of Carbonate data, seismic diffraction imaging has contributed to an enhancement in the quality of seismic but there is still lack of understanding the lithology and impedance contrast which can be defined by the seismic inversion. In contrast, to the conventional process, an integration of seismic inversion methods are necessary to understand the lithology and include the full band of frequency in our initial model to incorporate and detail study about the basin for prospect evaluation. In this paper, an integrated approch is developed for better deleniation of subsurface structure and lithologies. Seismic post stack inversion technique is applied to the Carbonate field to study Electroficies and lithofacies of subsurface strata for better and detail study of the reservoir.
The existence of elastic anisotropy in the reservoir is obtained through the equivalent media theory. An isotropic elastic theory fairly explains the reservoir modeling or characterization but its not well explain anisotropic characteristic fairly for reservoir characterization which is extremely challenging without considering a self-consistent theory of effective equivalent media theory. In this research, equivalent media theory has been explained and implemented on a producing well-log data with consistent Vp, Vs, density and other parameters. Instead of using Voigt averaging, equivalent media theory used to estimate the effective stiffness parameters and compare with Thomsen's parameters and finally used effective anisotropy parameters and compare with gamma log. Result shows the effectiveness of equivalent media theory for future application for developing reservoir modeling and characterization.
The success of drilling operations strongly depends on proper mud weight design. In fact, unsuccessfully optimizing the mud weight could lead to wellbore collapse. Within the oil industry, Mogi and Mohr-Coulomb models are the most-practiced failure criterion used in predicting critical mud weight.
This paper was aimed at inspecting these models regarding mud weight prediction. A new comparison concept was also developed. Furthermore, the different stochastic perspectives were carried out in the study. Based on field data, the required mud weight was found using the Mogi and Mohr-Coulomb failure criteria. The results suggested that the predicted pressure from the Mogi model is considerably close to the real mud weight. The study is also developed using the new pragmatic comparison criteria called the breakout width.
The predicted mud weight from both models was separately utilized to obtain the width of shear failure (breakout) by applying the simple analytical model. The results revealed the breakout dimension was a bit over-predicted with respect to the Mohr criteria. Moreover, the optimum mud weight was a function of input parameters, which include stresses and rock properties.
The knowledge of such parameters depends effectively on the quality of the parameters. The deterministic approach was presented to display the influence of each parameter by developing tornado diagrams. The analysis was defined that the maximum horizontal stress is the most influential parameter for collapse pressure prediction for both models. In addition, overburden stress has a considerable effect on the Mogi model and was ignored in the Mohr criteria. Other parameters were also captured in the analysis. In this paper, the probabilistic analysis approach using Monte Carlo simulation was also implemented into wellbore stability models to cover all the significant parameters with their uncertainties rather than certain values for improving predictions. Based on the analysis, the mud weight optimization will have a direct impact on future drilling practices and operation costs.
To date, several methods have been designed and implemented either individually or as combination to increase oil recovery. The combined methods also called hybrid Enhanced Oil Recovery (EOR) pose great challenges in the oil and gas industry. This is also confirmed from the Industry Technology Facilitator (ITF)'s Gulf Cooperation Council (GCC) Technology roadmap that pinpointed hybrid EOR as the top challenge. This work investigates the potential of a new hybrid EOR method termed Low Salinity Water Assisted Foam flooding (LSWAF). Typically, it consists of injecting Low Salinity Water (LSW) followed by an alternated injection of a Surfactant Aqueous Solution (SAS) and CO2 gas. The selection of LSW was based on its ability to produce significant changes of rock wettability. While the SAS was made, so that it results in a considerable reduction of IFT and produce foam that will remain considerably stable in the presence of oil under reservoir conditions. The selection of the best LSW and SAS followed a screening phase whereby formulations of different ion compositions and salinities were prepared and their performances were compared against each other. Tests were carried out by using two types of light crude oil with different Total Acid Number and Base Number, namely Crude oil A and B. In terms of changes in wettability, for both crude oils A and B, the experimental results revealed that much changes were experienced by the LSW of KCl composition followed by that of NaCl, then CaCl2, MgCl2, Mix composition, and finally the formation water (FW) that presented negligible changes. The changes with crude oil B were greater than crude oil A. However, for crude oil A and B, the core flooding experiments showed that the highest residual oil recovery was achieved by the LSWAF of KCl composition (87.45% of OOIP) compared to the MgCl2 and FW.
Mohd Hatta, Siti Aishah (PETRONAS Carigali Sdn Bhd) | Zawawi, Irzee (PETRONAS Carigali Sdn Bhd) | Gupta, Anish (PETRONAS Carigali Sdn Bhd) | Ahmad Nadzri, M. Safwan (PETRONAS Carigali Sdn Bhd) | Salleh, Nurfarah Izwana (PETRONAS Carigali Sdn Bhd) | Jeffry, Suzanna Juyanty M. (PETRONAS Carigali Sdn Bhd) | Sharif, Natasha Md (PETRONAS Carigali Sdn Bhd) | Ishak, Izza Hashimah (PETRONAS Carigali Sdn Bhd) | Maoinser, M. Azuwan (Universiti Teknologi PETRONAS)
Field B is a marginal green field located offshore Sarawak, Malaysia with formation depth of less than 1000 meters. The compressional sonic transit time range is from 100 – 115 μs/ft, which immediately triggered the possibility of using active downhole sand control as this range is assumed to be unconsolidated. However, the rock mechanical strength characterization tests from sidewall core indicated contradictory result of a consolidated formation. Since the field is considered as a small field, the cost of the well especially on downhole sand control device need to be extensively optimized. Hence, sand prediction study for a small green field development using field and laboratory measurements was performed.
Several methodologies of sand prediction were utilized to evaluate the optimum sandface completion and sand control management for the field. Empirical and analytical sand prediction based on the well logs, sidewall cores analysis, and sand prediction software are employed to evaluate the likelihood of sand production and the optimum well completion design for the field development. The available data from appraisal wells of Field B is also calibrated to the nearby brown field, Field A that has been producing for more than 30 years.
This paper will discuss on the sand onset prediction results between full perforation versus oriented perforation, and pressure depletion impact on the sand production. The study shows that the formation is not prone to sand production especially in the early part of the production life with high reservoir pressure and low watercut. The expected Critical Drawdown Pressure (CDP) generated from different methods show large variation of sand onset pressure if the sandface is completed using full perforation. Oriented perforation tremendously expands the sand free drawdown limit. Based on the results of the study, expected reservoir pressure depletion and watercut, the completion of the wells adopted Oriented Perforation with no other downhole sand control equipment.
This paper is beneficial for petroleum and well completion engineers especially on sand prediction part of well completion design in development stage. This will assist in ensuring the field meets the EUR and bring forward economic value as well as well integrity assurance.
Identification of areas with high hydrocarbon distribution within a field can be achieved if the field has electromagnetic data coverage. However, it is not the case for Field A which has led to the study of determining an improvised approach to achieve the purpose. SQp and SQs attributes which are formulated from seismic-attenuation rock physics were applied to Field A for hydrocarbon distribution prediction. These attributes can be computed with Vp/Vs and density parameters that can be achieved through elastic inversion. From the well logs, the SQp attribute response has some association with gamma ray whereas the SQs attribute resembles the resistivity log. This allow the attributes to be utilized as the lithology and fluid indicators. The results show that the SQp-SQs cross-plot provides good demarcation in delineating the sand, silt and clay. Besides that, the cross-plot also allows hydrocarbon reservoirs to be interpreted and increasing SQs values are corresponding to increasing hydrocarbon saturation. The extracted SQp maps from the channel reservoir zones show the sand distribution at the area of interest. It is observed that within the channel features, the SQp values are typically low (sand dominant), whereas within the flood plain region, it indicated high SQp values (mud dominant). The SQs maps show that high SQs values are related to high hydrocarbon saturation region (potential of more than 60%) based on the analysis from the SQp-SQs cross-plot whereas low SQs values are corresponding to high water saturation distribution. The application of SQp and SQs attributes in Field A helps to enhance visualization in terms of lithology and fluid distribution. The SQs attribute can be used as a tool for indicating hydrocarbon reservoir. It may also be utilized to detect the high hydrocarbon saturation area which is essential for economical evaluation and well planning.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 209A (Anaheim Convention Center)
Presentation Type: Oral