Dasgupta, Suvodip (Schlumberger) | Raina, Ishan (Schlumberger) | Povstyanova, Magdalena (ADNOC E&P) | Laer, Pierre Van (ADNOC E&P) | Baig, Muhammad Zeeshan (ADNOC E&P) | Casson, Neil (ADNOC E&P) | Marzooqi, Hassan Al (ADNOC E&P) | Suwaidi, Salama Jumaa Al (ADNOC E&P) | Ali, Humair (Schlumberger) | Subbiah, Surej Kumar (Schlumberger) | Mello, Ashish D' (Schlumberger)
Al-Shamali, Adnan (Kuwait Oil Company) | Mishra, P. K. (Kuwait Oil Company) | Verma, Naveen K. (Kuwait Oil Company) | Quttainah, Riyad (Kuwait Oil Company) | Al Jallad, Osama (Ingrain Inc.) | Grader, Avrami (Ingrain Inc.) | Walls, Joel (Ingrain Inc.) | Koronfol, Safouh (Ingrain Inc.) | Morcote, Anyela (Halliburton)
In Kuwait, the Najmah source rock is characterized by a complex diagenetic history and depositional variability. Accurate determination of the porosity and permeability logs is essential for improved petrophysical evaluation, which may not be properly performed using conventional methods. This complexity makes the conventional evaluation methods alone insufficient to determine porosity and permeability logs accurately. A major goal of this study was to produce high-resolution porosity-permeability logs for Najmah Formation using advanced digital analysis and geochemistry measurements.
Sixty (60) feet of continuous core were analyzed from an oil field in southwest Kuwait. The analysis started with dual-energy x-ray CT scanning of full-diameter whole core and core gamma logging. Plug-size samples were selected to represent the varying porosity and organic matter content along the entire core length. Two-dimensional Scanning Electron Microscopy (2D SEM) and three-dimensional Focused Ion Beam (3D FIB-SEM) images were acquired and analyzed to accurately determine the organic matter content and porosity. Matrix permeability was directly computed from the 3D FIB-SEM images using the Lattice Boltzmann method. The SEM porosity was calibrated by determining the amount of movable hydrocarbons at in-situ reservoir conditions based on geochemical analyses (XRF, XRD and LECO), pyrolysis indices, PVT data and adsorption isotherm experiments.
The digitally obtained porosity and permeability data showed a unique trend that was used to produce permeability at the core level. The integration between digital analysis and geochemistry data increased the estimated porosity and confirmed higher mobile hydrocarbon in the reservoir in comparison with the measured data at the surface. This produced a new porosity-permeability trend that was more representative of the reservoir conditions and caused a significant increase in the rock permeability.
The integration between the digital SEM analysis and the geochemical measurements was critical to estimate in-situ porosity and permeability characteristics of the tight formation under study. Moreover, this analysis provided an important tool for obtaining different high-resolution porosity and permeability logs based on various porosity considerations (effective, organic, inorganic, clay). This would lead to higher accuracy in determining reservoir properties for improved quantification of reserves and productivity.
Dernaika, Moustafa R (Ingrain Inc) | Sahib, Mohammad Raffi (Kuwait Oil Company) | Gonzalez, David (Ingrain Inc) | Mansour, Bashar (Ingrain Inc) | Al Jallad, Osama (Ingrain Inc) | Koronfol, Safouh (Ingrain Inc) | Sinclair, Gary (Ingrain Inc) | Kayali, Anas (Ingrain Inc)
Detailed core characterization is often overlooked in the sampling process for core analysis measurements. Random core sampling is usually performed and the selected plugs are not associated with rock types or the reservoir heterogeneity. The objective of this study is to obtain representative samples for direct simulation of petrophysical and fluid flow properties in complex rock types.
A robust sampling strategy was followed in reservoir cores from two successive heterogeneous carbonate and siliciclastic formations in the Raudhatain field in Kuwait. The sample selection criteria were based on statistical distribution of litho-types in the cores to ensure optimum characterization of the main reservoir units. The litho-types were identified based on porosity and mineralogy variations along the core lengths utilizing advanced dual-energy X-ray CT scanning. High resolution micro-CT imaging and subsequent segmentation provided 3D representation of the pore space and geometric fabric of the core samples. Primary drainage and imbibition processes were simulated in numerical experiments using a pore-scale simulator by the Lattice Boltzmann Method. Capillary pressure (Pc) and relative permeability (Kr) curves together with water and oil distributions were investigated for complex geometries by the different rock types.
The dual energy CT density was compared with wireline log and provided accurate calibrations to the downhole logs. The different rock types gave distinct capillary and flow properties that can be linked to the rock structure and pore type of the samples. The Lattice Boltzmann based pore-level fluid calculations provided realistic fluid distributions in the 3D rock volume, which are consistent with pore-scale physical phenomena.
This characterization method by the dual energy CT eliminates sampling bias and allows for each cored litho-type to be equally represented in the plugs acquired for subsequent petrophysical and fluid flow analyses. It also provides accurate calibration tool for downhole logs. The digital analysis gave reliable SCAL data with improved understanding of the pore-level events and proved its effectiveness in providing advanced interpretations at multiple scales in relatively short timeframes.
Veedu, F. Koyassan (DeGolyer and MacNaughton) | Dharanidharan, B. (DeGolyer and MacNaughton) | Tye, R. (DeGolyer and MacNaughton) | Prasse, E. (DeGolyer and MacNaughton) | Flagg, S. (DeGolyer and MacNaughton) | Hornbrook, J. (DeGolyer and MacNaughton) | Ahmad, F. (Kuwait Oil Company) | Al-Dohaiem, K. (Kuwait Oil Company) | Jha, M. (Kuwait Oil Company) | Bagheri, M. (Kuwait Oil Company) | Sanyal, T. (Kuwait Oil Company)
This paper summarizes a reservoir modeling study involving the evaluation of development strategies relevant to a newly discovered, unconsolidated sandstone heavy oil field in Kuwait. The methodologies used provided essential information to define and evaluate feasible options to develop the reservoir.
A reservoir model was developed utilizing seismic, well-log, and core data. Petrophysical estimates of mineralogy, porosity, water saturation (Sw), and permeability were made and calibrated to core data. The field geology and the depositional analog guided the interpretations of the reservoir geomorphology and sediment-distribution patterns. Facies modeling was achieved through multiple-point statistics methodology. Porosity, permeability, and Sw were distributed using Sequential Gaussian Simulation. Various sensitivity runs were made for key parameters to understand the uncertainty of the model forecast. A full-field reservoir model (FFRM) was developed by incorporating available engineering analysis data. Development potential of the field through pressure depletion was studied through full-field reservoir simulations. Considering the high level of uncertainty of a new field, Low, Mid and High forecast cases were established for development through pressure depletion. Simulations of secondary and tertiary recovery techniques were then evaluated through sector model simulations and upscaled to field level. Finally, roadmaps were laid out for several development scenarios considered for the field.
This paper demonstrates how various geological, petrophysical, and engineering data were used to build a representative full-field geocellular model (FFGM) and make field-performance forecasts under uncertainties pertaining to a green, heavy-oil field. During the model development stage, dielectric and elemental spectroscopy log data were utilized to enhance the petrophysical analyses. The distribution of Sw followed a distinct workflow where the distribution within each reservoir zone was based on several oil/water contacts (OWC). Available pressure-volume-temperature (PVT) analysis data were used to estimate and confirm the presence of water zones within the reservoir intervals.
Steiner, S. (ADCO) | Raina, I. (Schlumberger) | Dasgupta, S. (Schlumberger) | Lewis, R. (Schlumberger) | Monson, E. R. (ADCO) | Abu-Snaineh, B. A. (ADCO) | Alharthi, A. (ADCO) | Lis, G. P. (Schlumberger) | Chertova, A. (Schlumberger)
ADCO started its unconventional exploration campaign in 2012 targeting the tight carbonate sequences known as Wasia Group, onshore Abu Dhabi. A front-end loaded data gathering strategy was employed to acquire extensive latest generation logging data tailored for unconventional reservoirs. In a number of wells the entire reservoir section was cored, often up to 800 ft per well, leading to more than 3000 ft of core retrieved to date. ADCO applied unconventional core analysis technologies, such as retort analysis, to generate the optimal core results. Key parameters such as effective porosity, pore size distribution, TOC, source rock maturity, mineral compositions and fluid saturations were determined from logs and core data (where available).
This paper will focus on the petrophysical challenges during the evaluation of the Wasia Group. We will demonstrate that conventional core analysis techniques have only limited applicability, whereas core analysis techniques designed specifically for unconventionals provide more relevant results. A log analysis methodology centered on the application and importance of NMR in unconventional liquid plays is presented. Porosity data measured through retort analysis provide an excellent fit to NMR log-based porosity measurements. Conventional core analysis results generated a poor fit to log porosity, and the resulting values exhibited scatter with a large standard deviation.
Log data-derived rock typing was performed. It is based on principal component analysis of the reservoir section. Rock classification may help in selecting suitable zones for hydraulic fracture initiation.
Lessons learned from the initial wells for core recovery and analysis techniques are summarized below and have been implemented in later wells: Preserve part of the core for robust saturation measurements. Stop acquisition of conventional poro-perm data Focus on unconventional-specific retort-based techniques for core petrophysics Focus on pulse decay permeabilities Use scratch test to aid in core analysis sample selection process, especially for rock mechanics Add core
Preserve part of the core for robust saturation measurements.
Stop acquisition of conventional poro-perm data
Focus on unconventional-specific retort-based techniques for core petrophysics
Focus on pulse decay permeabilities
Use scratch test to aid in core analysis sample selection process, especially for rock mechanics
The complete integration of core and log data has allowed for a thorough assessment of the unconventional hydrocarbon potential within the ADCO concession.
Golab, A. (FEI Digital Rock Services) | Deakin, L. (FEI Digital Rock Services) | Ravlo, V. (FEI Digital Rock Services) | Mattisson, C. (FEI Digital Rock Services) | Carnerup, A. (FEI Digital Rock Services) | Young, B. (FEI Digital Rock Services) | Idowu, N. (FEI Digital Rock Services) | Al-Jeri, S. A. (Kuwait Oil Company) | Al-Rushaid, M. A. (Kuwait Oil Company)
A study was designed to confirm the formation properties obtained from available conventional RCA data and inferred from corrected wireline log data using digital rock analysis (digital RCA and SCAL analysis) on cores from the Greater Burgan field. This study was performed for Kuwait Oil Company, Fields Development Group (S&EK) by FEI Digital Rock Services in 2014.
As part of this study, 27 feet of whole core, from the Lower Ahmadi (AHL2) to Upper Wara (WU1) formations, were imaged by X-ray computed tomography (CT) imaging, including 1 foot of partially preserved core. 14 plugs were extracted from these cores and imaged in 3D by a high resolution helical micro-CT. Analysis revealed stark differences in mineralogy, grain size and sorting and the presence of severe fracturing in some plugs due to the fragility and friability of the rock.
Sub-plugs were extracted from 10 of the 14 plugs (including one sub-plug from the partially preserved section) and imaged in 3D by helical micro-CT. 7 of the sub-plugs proved suitable for digital RCA and SCAL analysis. The 3D images were used to calculate digital RCA properties (porosity, permeability, grain density, grain size distribution and formation factor) and pore network models were built to perform digital SCAL simulations and predict multiphase transport properties such as Pc, kr and resistivity index for primary drainage and imbibition.
In addition, the
A tight rock workflow was used to identify sub-resolution porosity in 3 of the plugs. Experimental MICP curves showed that substantial portions of the pore throats were below the image resolution, caused by large amounts of pore-filling materials. Hence, pore scale information could not be directly extracted from some images. Consequently, process based modelling was carried out on two plugs to generate pore-networks. A quasi-static pore-network model was used to simulate oil/water displacements and predict multiphase transport properties. Detailed imaging of oil-in-place and porosity was performed on a partially preserved plug to create a map of remaining oil which revealed that oil was retained in most porous grains and strongly retained in clay-rich zones.
The digital core analysis results are in agreement with available log and core data. The Lower Ahmadi (AHL2) section is good quality in terms of porosity, permeability and flow properties, whereas the Upper Wara (WU1) section is of poorer quality.
Kumar, Sanjeev (Kuwait Oil Company) | Al-Hamad, Hamad (Kuwait Oil Company) | Al-Bous, Faisal (Kuwait Oil Company) | Al-Mutairi, Fayez (Kuwait Oil Company) | Sanyal, Arunava (Kuwait Oil Company) | Safar, Ahmad (Kuwait Oil Company)
A number of heavy oil or tar accumulations have been reported in several Middle East reservoirs. Heavy oil is often overlooked as a resource because of the expense and technical challenges associated with producing it.
But more than 6 trillion barrels of oil in place attributed to the heaviest hydrocarbon. Most of the conventional onshore hydrocarbon reservoirs have been depleted, and time of easy hydrocarbon is over; so, it is prudent to look into the unconventional reservoirs like heavy oil. An accurate evaluation and characterization is obviously crucial to its efficient exploitation. The evaluation and characterization of heavy oil depends on its identification, quantification, analysis of representative fluid sample and reservoir properties.
The methods proposed in the literature might be successful in identifying heavy oil reservoirs but are less reliable for quantifying the amount of heavy oil, and are insensitive to oil viscosity, the key property that controls the producibility of heavy oil. Heavy oil characterization is incomplete without the sampling of fluid in the reservoir environment. It is often desirable to acquire the sample with wireline formation tester tool and integrate the in-situ fluid properties with NMR logs.
In this study we successfully integrate, conventional logs, NMR logs, in-situ fluid sample, PVT data and conventional core data for identification and quantification of heavy oil present in the pore space. This integrated study overcomes the limitations of individual techniques. Our case study shows that the porosity deficit between conventional total porosity and NMR porosity gives the identification of heavy oil present in the pore space, this difference between two porosities represents the extra viscous component of fluid that are not observable by the NMR tool. The amount of porosity deficit is the amount of extra heavy oil / tar in the pore space and this gives the quantification of the same.
Conventional and NMR derived reservoir properties are required to be integrated with conventional core porosity, permeability, water saturation and viscosity derived from PVT sample in order to characterize Heavy Oil in Clastic Reservoirs.
Nilotpaul, Neog (Kuwait Oil Company) | Narahari, Srinivas Rao (Kuwait Oil Company) | Al-Darmi, Areej (Kuwait Oil Company) | Al-Dousiri Musaed, Yaseen Makki (Kuwait Oil Company) | Rawan, Hussain Al-Mayyas (Kuwait Oil Company) | Tom, De Keyzer (Technically Writes Consultancy) | Peter, Swart (CSL, University of Miami) | Kendall, Christopher G.St.C. (University of south Carolinian)
Field development in complex carbonate evaporite reservoirs has been a challenge for geoscientists by using simple sedimentology based geological models. A high resolution sequence stratigraphic framework has been designed from a conceptual 3D depositional model to a deterministic predictable model. In this process framework boundaries have been fine-tuned with carbon and oxygen isotope signals and defining ichno-facies associations to map lateral continuity of member formations within Marrat sequence. As dolomites and porous grain stones are the key reservoir quality rock types for Marrat Group of formations, position of precursor lithofacies in sequence stratigraphic frame work is found to be crucial. Dolomite samples are analyzed for d13C and d18O. Upper and Lower Marrat members are characterized by thinly laminated, micro crystalline exposure dolomites and high in d18O signal which are associated to low stand packages, whereas Middle Marrat dolomites are relatively low in d18O and high in d13C are associated to high stand precursor facies. Moreover, typical ichnofacies association of porous dolomites defining vertical heterogeneity and lateral connectivity of flow zones in Middle Marrat reservoirs. The reliability of this model has been established through recent tested intervals, with production logging and formation pressure tester data integration demonstrates predictability of flow zone connectivity.
Pepin, Alexandre Henri Angelo (Schlumberger) | Bize-Forest, NadÃ¨ge (Schlumberger) | Montoya Padilla, Sandra Janette (Schlumberger) | Abad, Carlos (Schlumberger) | Schlicht, Peter (Schlumberger) | de Castro Machado, Alessandra (Universidade Federal do Rio de Janeiro) | Lima, InayÃ¡ (Universidade Federal do Rio de Janeiro) | de Paiva Teles, Atila (Universidade Federal do Rio de Janeiro) | Tadeu Lopes, Ricardo (Universidade Federal do Rio de Janeiro)
Hydrocarbon production optimization in Pre-Salt carbonate reservoirs is a main focus for oil and gas research in Brazil. Stimulation treatment design optimization requires good knowledge of the reservoir properties and excellent understanding of the interaction between rock formation and treating fluid. This paper investigates these interactions through laboratory tests determining the compatibility of fluids used in matrix stimulation with different Pre-Salt carbonate rock types. The objective of this work is to relate the geology, petrophysics, and geomechanics of the Pre-Salt reservoirs to their expected stimulation response.
Because of the difficulty in obtaining downhole cores and the destructive nature of most tests, the study focused on samples collected from a Pre-Salt carbonate analog: the Coquinas formation (Schafer 1973) from the Sao Miguel quarry, northeast Brazil (Chagas de Azambuja Filho et al. 1998). A thorough geology-based study of the Coquinas formation, including routine core analysis (FZI) microtomography, and thin section study was conducted. Usually these grain-supported carbonates show different amounts and types of primary porosity, closed and reopened by multiple diagenetic phases.
Throughout the 25-m thick Coquinas reservoir, five rock types in 13 layers with permeability ranging from microdarcy to almost 1 darcy were identified. All rock types were subjected to routine mineralogy evaluation and various petrophysical, geomechanical, and spectroscopic measurements. Six of the thirteen layers were selected to perform core flow tests with a viscoelastic surfactant technology based diverting acid fluid (Al-Mutawa et al. 2005; Chang et al. 2001; Samuel et al. 1997). This is the first extensive study reporting the efficiency of a viscoelastic diverting acid system in the Pre-Salt analogue Coquinas carbonate formation outcrop cores. Spectroscopic measurement showed wormhole creation and, in some cases, rock texture alteration or fine migration. Through the study we identified the flow units and characterized the rock behavior when chemically stimulated. The conclusions from this study will enable us to tailor and optimize stimulation treatments of Pre-Salt carbonate reservoirs.
The offshore Pre-Salt in Brazil comprises a group of recently discovered fields with promising oil reserves in the Coquinas formation or the above the microbialites section. For example, Lula (ex-Tupi) field, the lead field of the Santos cluster, is believed to hold between 5 to 8 billions barrels of oil equivalent (Beltrao et al. 2009). The Pre-Salt reservoirs are currently the focus of research in Brazil; however, the scarceness of downhole samples collected makes destructive tests very difficult to perform, and so analysis must be performed on analogues. The onshore Coquinas formation from northeast Brazil is taken here as analogue of the Pre-Salt carbonates.
We aim to demonstrate the use of high-resolution sedimentological data during the early phase of the exploration cycle. The data reviewed included more than 1300 m of log sections taken North of Erbil. This was combined with field mapping, a microfacies study and the acquisition of routine core analysis data from plugs to provide a more complete analysis. Subsurface data included lithological information from two wells and 2D seismic lines with a total length of 487 Km.
The study focussed on carbonate sequences including potential and known hydrocarbon reservoirs, notably the Qamchuqa-, the Shiranish-, the Khurmala- and the Pila Spi Formations. As a result a refined stratigraphic and depositional framework for the Lower Tertiary and Upper Mesozoic sequences has been established. The Cretaceous sequences analysed herein display a series of distinct lithofacies types ranging from shallow marine to deeper marine environments, which can be attributed to different main depositional complexes. The Paleogene sequences show a high diversity of lithotypes that relate to fluvial, fluvio-marine, mixed siliciclastic - carbonate shelf and inner platform depositional environments.
Outcrop samples from both Tertiary and Cretaceous dolomites inherit the highest porosities thus presumably best reservoir quality in the subsurface. However, the effect of fracturing cannot be assessed in detail from surface data alone.
A 3D facies model has proven useful in displaying the spatial relationship of the well and outcrop data. The display of facies probabilities improves the recognition of cyclicity within homogeneous dolomite sections. Possible extent and connectivity of geobodies could be assessed with the model.
The results have been compared with, and put into a regional context with data from literature and proprietary selected subsurface data. The outcrop data have been incorporated into a workflow that supported other G&G subsurface disciplines during the exploration phase.