Couto, M. R. (University of Minho) | Gudiña, E. J. (University of Minho) | Ferreira, D. (University of Minho) | Teixeira, J. A. (University of Minho) | Rodrigues, L. R. (University of Minho) | Soares, L. P. (Partex Oil and Gas) | Ribeiro, M. T. (Partex Oil and Gas)
Polymer-flooding is one of the most promising techniques used to increase the productivity of mature oil reservoirs. Polymers reduce the mobility ratio of the injected water relative to the crude oil, improving the displacement of the entrapped oil and, consequently, increasing oil recovery. Biopolymers such as xanthan gum have emerged as eco-friendly alternatives to the chemical polymers commonly used by the oil industry. However, in order to seek for more efficient biomolecules, alternative biopolymers must be studied. In the present work, the biopolymer produced by
Reservoir modeling involves the characterization of the internal gridded petrophysical properties distribution and the simulation of fluid production. However, a common problem associated with reservoir modeling is the highly non-linear relationship between the distribution of the petrophysical parameters (frequently with a non-stationary character) and the fluid production. To tackle this problem, this paper presents a new methodology for integrated reservoir modeling by addressing a multiscale optimization approach applied for non-stationary geostatistical history matching of complex connectivity hydrocarbon reservoirs.
The methodology comprises a two staged procedure for multiscale optimization, which includes a global optimization stage followed by a local refining stage. The former consists of optimizing the geological spatial anisotropy trend by coupling the stochastic optimization over the anisotropy multiparameter space with an image generation algorithm - direct sequential simulation with local anisotropy correction. The latter aims at refining the small scale heterogeneity by performing the local optimization based on a regional image perturbation method. The local refining optimization is achieved by taking into account the best individual well production matches.
A complex deltaic reservoir case study is presented to illustrate the applicability of the proposed methodology. An ensemble of multiple optimized history matched models is obtained respecting both the production data and the geological settings. The results show that the deltaic complex channelized pattern is well reproduced and also that the multiscale optimization improves the match between the simulated fluid profiles and the observed production data. As such, optimization is performed at multiple scales: the anisotropy trend model accounts for larger scale variability of the structures, while consecutive local refining improves convergence to dynamic response around individual wells.
The contribution of this work to petroleum technology is the implementation of a novel methodology for the reproduction of the fluids production profiles through the perturbation of the subsurface petrophysical models while honoring complex geological constrains.
Carbonate reservoir characterization is often a complex task, due to the interplay between primary processes (e.g. depositional environments, facies changes) and secondary processes (e.g. burial, diagenesis, faulting and fracturing, cementation). In order to properly characterize and model such a reservoir, it is paramount to unravel the order by which such processes have affected the rock, leading to the present day petrophysical properties.
In the presented case study (onshore dolomitized carbonate reservoir in Central Asia), a multi-step approach was taken for its characterization and modelling. The characterization phase was focused in understanding the key processes and controls on porosity and permeability. From the core and log data, a detailed sedimentologic and diagenetic study was performed, to identify the depositional environments and facies, as well as the pore system geometry, and its impact on fluid flow. Furthermore, several trends on reservoir quality were identified, related to faults, and associated with depositional cyclicity.
From the above work, a reservoir model was built, to support field development planning and associated uncertainties. A structural and stratigraphic framework was built, and Flow Unit Types (FUT) were defined using seismic, cores, thin sections, logs and mercury injection capillary pressure data (MICP). Property modelling was carried out for porosity and permeability, honouring FUT, depositional and diagenetic trends. In particular, two trends were modelled: a fault-related trend, to introduce the impact of diagenetic leaching related to faults (observed in core data); and a cyclicity related trend, to introduce the impact of preferential fluid flow pathways that occur at or near cycle tops. The uncertainty in the reservoir property models was evaluated with different FUT, driven by depositional and diagenetic concepts.
The results indicate that a significant improvement in reservoir understanding can be achieved with the use of an integrated study and model workflow, focusing on the key control factors that affect the pore system and the distribution of permeability. In this way it was possible to recognize spatial trends and capture the relationship between petrophysical properties, pore architecture and sweep efficiency.
Project partners want field operators to achieve production targets and deliver projects in the defined timeframe within budgetary limits. However, operators are frequently unable to achieve the goals projected at the launch stage of the project. This compromises the initial project economic value and originates conflicts between partners’ anticipations and the actual project outcomes. Such inconsistency is frequently due to wrongful and/or insufficient perception on risk management policies employed by both parties: operators often compromise the application of a holistic risk management framework, by concentrating their efforts around particular project segments, such as HSE, fluids production and/or oil price; partners, being heavily dependent on operator efficiency and competence, have limited tools to control project performance and usually rely or accept selected risk management methods.
This paper presents a general risk management approach for the oil and gas industry based on the knowledge gained in petroleum projects. The proposed methodology offers a coherent approach, which can aid in improving the risk management strategy of both operators and partners. The challenge is in developing a simplistic, but yet effective and dependable method, which can be utilized by consortiums in any oil and gas ventures.
The result of this paper is a Risk Management Roadmap (RMR) that provides all stakeholders with concrete tools to assess and categorize project risks, quantifying their potential economic impact and hold major threats within acceptable levels.
This paper attempts to provide relevant implications for both parties: operators enable an effective communication with partners facilitating a clear and common language for mutual cooperation and progression towards the project targets; partners benefit from taking better informed decisions, protecting shareholders’ interests, having stronger control and influence over the desired project outcome.
Many petroleum projects are being executed through the partnerships where operator “holds the rights to exploration and development of petroleum resources” with the objective to deliver the promised value of the project. Partners “make the investments needed to meet projected demand for oil” being focused on protection of shareholders’ interests and successful performance of their asset. Despite this, many projects fail to deliver on costs, schedule, operability and safety commitments resulting in disappointed financial outcomes and deterioration of the relationships between stakeholders. In this instance, effective management of risks becomes critical for both parties.
In oil and gas partnerships, the level of the project control tends to vary according to the role of the participants: operator has a direct control and responsibility over the project execution, being also accountable for the development of an effective Risk Management (RM) system; partners tend to provide technical and financial support relying on the effectiveness of the RM methodology chosen by the operator.
Reservoir characterization and modelling of highly heterogeneous carbonate reservoirs encompasses the interplay between petrophysical properties, facies, diagenesis, and their relationship with depositional environments. This case study describe a strongly dolomitized carbonate reservoir of Valanginian age onshore Kazakhstan, Central Asia. A reservoir model was built by using an integrated workflow with all the available data, namely seismic, cores, thin sections, logs and MICP. In order to build a robust subsurface model and reduce uncertainties, reservoir rock types (RRTs) were defined and modelled honouring depositional trends and diagenetic attributes.
Due to the complexity of the reservoir, the Winland R35 method, together with Lorenz plots and petrophysical groups, was used to derive the RRTs and to assign a porosity-permeability relationship for each RRT. The uncertainty in the reservoir property models was evaluated with different RRT connectivity scenarios, driven by depositional and diagenetic concepts.
With the integration of diagenetic trends in the model, it was possible to capture the heterogeneity of the reservoir and better understand the porosity and permeability distributions. This has led to development plan optimization through the definition of sweet spot areas and an improved STOIIP calculation.
The results indicate that a substantial improvement in reservoir understanding can be achieved with an integrated reservoir characterization and modelling process that accounts for depositional and diagenetic trends, especially in reducing subsurface uncertainty. Furthermore, it was possible to recognize spatial trends and capture the relationship between petrophysical properties, pore architecture and sweep efficiency. It is expected that the ultimate recovery will also improve.
The case study field is located onshore Kazakhstan, and comprises several oil bearing units. The principal reservoir corresponds to Aptian deltaic-marine sands, whereas this study addresses a secondary reservoir, which is the Valanginian carbonate. The producing structure is an E-W oriented anticline with a western downdip, where some faults are present.
The Carbonate reservoir was discovered as an upside in the mid-2000’s while drilling an exploration well. Encouraging flow tests from a 6 m interval have led to the kick-off of a detailed reservoir modelling exercise, in order to support a development plan. After that, a first pass static model was done with just a few wells. More recently, several appraisal wells were drilled to delineate the extent of the Carbonate reservoir.
The Valanginian Carbonate comprises fine grained limestone, dolomite and marl. This total interval is some 370-400 m thick (Figure 1). The oil bearing unit itself occurs in the uppermost part of the interval, and is mainly composed of skeletal dolopackstone, dolowackestone/dolopackstone, doloboundstones, with some intervals of dolomudstones. This oil bearing unit presents layer cake geometry, and is sealed by anhydrite.
This paper describes the work undertaken to build a 3D static model of a Lower Cretaceous Carbonate Reservoir located in Kazakhstan called X-Field. This reservoir has been pervasively dolomitized, and presents several challenges for development optimization. This model will be used to support further appraisal and development activities, in order to tackle key uncertainties, such as reservoir quality distribution.
All of the available data were quality controlled, analyzed and interpreted (including data from logs and cores), to produce porosity, permeability and RRT (reservoir rock type) models. These are believed to be representative of the reservoir's behavior and connectivity.
In order to identify the main flow zones and understand the reservoir's complexity, Reservoir Rock Typing (RRT) was performed on two cored wells by analyzing CCAL and SCAL data, including thin sections, MICP measurements, porosity and permeability. A comprehensive RRT methodology using Winland R35 method and poro-perm plot was followed, which resulted in defining five rock types. The outcome from the RRT study was confirmed by poro-perm plot, which showed the presence of five flow units.
The 3D model was built by using corner point grids (CPG), and contains a total of 2,380,050 cells. Several models of porosity and RRT were generated, representing "low??, "mid??, and "high?? case scenarios of reservoir quality distribution. Finally, permeability models were created for each scenario, conditioned to their respective Winland R35 porosity-permeability relationships per RRT.
Comparison between the different porosity (F), permeability (k), and RRT models and scenarios, will allow a better management of the reservoir uncertainties during the appraisal and development stages for this reservoir.
Guerreiro, Luis (Partex Oil & Gas) | Carvalho, Clvaro Lopes Belo (Partex Oil and Gas) | Maciel, Carlos (Partex Oil and Gas) | Sousa, Jose (Partex Oil and Gas) | Caetano, Hugo (Partex Services Portugal) | Soares, Laura Palma (Partex Oil & Gas) | Carneiro, Silvio (Partex Oil & Gas) | Castanho, Sofia (Partex Oil & Gas) | Machado, Vasco
Marginal fields based upon complex reservoirs present to the operating companies real challenges in terms of the implementation of viable full field development plans (FFDP). Small NPVs imply a constant and tight costs control and a careful balance between the data gathering cost and the value of the information that can be retrieved from that data.
The fields under analysis are located in the onshore Potiguar Basin, NE Brazil. Productive reservoirs are composed by shallow interbedded sandstone channels and fine shale laminations with complex geometry. Seismic imaging has very poor quality and petrophysical interpretation presents a major challenge due to the presence of fresh formation water.
The absence of strong aquifers associated with low initial reservoir pressures and a negligible GOR led to the use of artificial lift and, in a near future, the implementation of a water injection scheme. The oil is paraffinic with low pour point temperatures, which easily creates conditions for high deposition of paraffins. All these factors induce very low productivities, ranging from 100 to 300 bbld with high water cuts.
An out of the box thinking attitude was fundamental for Partex to be able to design and implement a sound FFDP, which included the building of consistent static and dynamic models, where uncertainties were identified and quantified. Uncertainty reduction was tackled both through planified but limited data gathering campaigns and compilation of existing analogue data. Operational cost reduction without compromising HSE standards was implemented through innovative well drilling and design and a phased development scheme associated with long term testing (early production schemes).
Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
The Thamama B reservoirs in Abu Dhabi onshore fields represent over 50% of the total reserves of the country. Therefore, the optimization of production and the maximization of recovery are of paramount importance. While reserves are distributed uniformly in the reservoir, the permeability distribution is heterogeneous, with top layers being more permeable (100 mD to 1 D) than lower ones (1 to 10 mD). This has a strong impact on water flooding performance and requires a thorough understanding of the reservoir fluid flow physics and behaviour, focusing on the detailed analysis of the water hold-up and slumping mechanisms, including the origin and shape of the existing water cones in the lower zones and the bypassed oil zones.
Study results showed that the management of Thamama B reservoirs needs to be achieved through the combination of high quality field surveillance programmes, associated with detailed reservoir studies developed specifically for the modelling of the water advance in the reservoir.
A mechanistic model of a Thamama B reservoir in an Abu Dhabi onshore field was created to determine which parameters, and respective uncertainty ranges, have the greatest impact on fluid dynamics. These were identified to be: rock wettability, (and the associated capillary pressure and relative permeability curves), and the presence of high permeability and dense intervals within the reservoir, both in the upper and lower zones. Once the parameters are identified, it is then vital to reduce the associated uncertainty, by fine tuning the models and undertaking representative forecasts.
The hereby proposed way forward concentrates on monitoring the reservoir performance and build refined reservoir models that can be easily used to understand the reservoir mechanisms and to characterize and accurately predict the water movement in the Thamama B reservoirs, in order to be able to establish the most adequate field development methodologies leading to the optimization of production and to the maximization of ultimate recovery.
Lawrence, David A. (ADCO) | Al Ali, Malalla (Abu Dhabi Co. Onshore Oil Opn.) | Vahrenkamp, Volker C. (Abu Dhabi Co. Onshore Oil Opn.) | Al Shekaili, Fatema (Abu Dhabi Co. Onshore Oil Opn.) | Yin, Yahui (ADCO Producing Co. Inc.) | El Wazir, Zinhom Ali (Abu Dhabi Co. Onshore Oil Opn.) | Ribeiro, Maria Teresa (Partex Oil and Gas) | Mueller, Klaus W. (Abu Dhabi Co. Onshore Oil Opn) | Al-Madani, Noura Mohammed (ADCO Producing Co. Inc.)
A super-giant carbonate field in Abu Dhabi has most of its remaining reserves in carbonate build-up and prograding basinmargin deposits of Lower Cretaceous age (Shuaiba Formation). To guide further field production, a sequence stratigraphic framework was developed based on integration of core, log and seismic data. This framework is the cornerstone for building a new reservoir model and provides the key for a better understanding of facies and flow unit continuity guiding present and future field production and performance.
Approximately 730 wells, wireline logs and the latest core descriptions were integrated for this study. Another key element was the incorporation of 3D seismic data coupled with several iterations between well log and seismic picking. Detailed seismic interpretation led to the delineation of 3rd and 4th order sequences. The picking of higher order sequences was based on well data guided by the seismic surfaces. This study provides an excellent example of extracting maximum information from seismic and the full integration of geoscience and production data to provide a new 3D framework.
The sequence framework uses a consistent nomenclature based on the Arabian Plate Standard Sequence framework for the Aptian (van Buchem et. al., 2010). The Shuaiba is subdivided into six 3rd order sequences (Apt 1, 2, 3,4a, 4b, and 5) which, based on stacking patterns, record a complete 2nd order cycle of Transgressive, Highstand, and Late Highstand systems tracts (Apt 1-4b). The Bab Member (Apt 5) and Nahr Umr Shale form the Lowstand to Transgressive systems tracts of the next Super-sequence.
The third order Apt 1 sequence and the Apt 2 TST form the 2nd order transgressive systems tract, characterized by backstepping and creation of differential relief between the Shuaiba shelf and Bab intra-shelf basin. These sequences are dominated by Orbitolina and algal/microbial Lithocodium/Bacinella fossil associations.
The Apt 2 HST and Apt 3 Sequence form the 2nd order early highstand systems tract during which the platform area aggraded and the topographic split into platform, slope and basin became most pronounced. Sediments are extremely heterogeneous and varying properties introduce significant problems in understanding fluid flow. During the regressive part of the Apt 3 sequence accommodation space was limited and deposition switched to progradation at the platform margin. The platform top is characterized by thin cycles of rudist floatstones/rudstones separated by thin cemented flooding and exposure horizons, whilst
the platform margin received large quantities of rudstones, grain and packstones organized in clinoform sets. Clinoforms are separated by thin stylolitic cemented layers, which are transparent on seismic.
The Second Order late highstand systems tract is composed of 3rd order cycles Apt 4a and Apt 4b. These are detached from the main buildup, which probably stayed largely exposed, and form strongly prograding slope margin wedges composed of alternating dense mudstones (TST) and grainstone/packstone sequences with coarse grained top-sets which formed during highstand phases. Lowstand deposits of the Apt 5 cycle (Bab Member) are dominated by fine-grained siliciclastics capped by thin oolitic carbonate facies which are isolated from the main part of the field and are not hydrocarbon charged.