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Abstract This paper presents the successful application of a new-generation slim pulsed neutron logging tool for identification of bypassed oil in the Nong Yao field. The field comprises of different small pools of oil developed with horizontal wells. The wells are drilled with long lateral sections to increase the drainage area in an attempt to increase sweep efficiencies. However, the sweep efficiencies remained uncertain given reservoir heterogeneity and the nature of water encroachment into the wells. Reservoir saturation monitoring through tubing is usually required for an effective reservoir management program in such a mature field, and a cost-effective method for future opportunity identification. The traditional slim pulsed neutron logging (PNL) tools often provided inconclusive results especially when deployed in complex completion conditions. A new-generation slim pulsed neutron logging tool, which provides high-resolution spectroscopy with a much-improved accuracy and precision was investigated and introduced. This tool delivers self-compensated sigma and neutron porosity measurements in a wide range of conditions, including complex completions and with varying amount of gas in the wellbore or annulus. This new PNL tool was run in the Nong Yao field in December 2017 with the objective to prove the remaining oil at the top of a reservoir. The objective was to acquire data in GSH (sigma, fast neutron cross section, Porosity) and IC (spectroscopy) modes in 8-1/2" hole with conventional completion (7" casing + 2-7/8" tubing). Despite challenging borehole fluid conditions, the data acquired confirmed remaining oil in the reservoir and a new well drilled in 2018 targeting this bypassed oil is currently producing with very good oil production. This successful implementation of PNL in 2017 led to the adoption of the tool as a good alternative for confirming bypassed oil in the Nong Yao field. This strategy has been adopted for well target validation and horizontal well placement to support the 2019-2020 infill drilling campaigns. In December 2018, this tool was run again in three selected candidate wells to prove the remaining bypassed oil and oil saturation away from currently producing wells. The results acquired in all three cases showed clear oil/water contact movement and sweep where present, confirming sufficient remaining oil volume to justify the drilling of new infill wells to develop these volumes during the 2019-2020 infill drilling campaigns. The new generation PNL tool provides a low-cost alternative for effective reservoir depletion monitoring. Proper reservoir management, additional opportunity identification, and infill drilling target optimization are all benefits that can accrue from accurately locating bypassed oil. Field development plans can then be further optimized, resulting in increased asset value.
Abstract Sand management is one of the key component of Bongkot production processes. Current sand production prediction is based on a model which requires sonic and density logs for all the wells. However, a combination of complex well architecture and focus on reducing well cost resulted in many wells not having acquired these important logs. This project has implemented new technique of "Artificial Neural Network" to solve this problem. Using this method, synthetic logs are generated to obtain the values of missing sonic and density data. These data are then used in the existing sand models to predict sand production potential. This project was evaluated with three field cases. The sand failure predictions based on synthetic rock properties matched with actual sand production. Therefore, the sand prediction workflow has been updated to include log synthetic if acroustic or density log are missing.
I present a new workflow that has been used to build detailed data-driven rock physics models of various prospective unconventional shale intervals within the Permian Basin of the US, and the Horn River and Western Canadian Sedimentary Basins of Canada. A couple of simple approximations enable us to estimate depth-varying in-situ geophysical properties (Vp, Vs and density) for the three commonly-defined and often volumetrically-dominant mineral groups – carbonates, clays and silicates. Confidence that these estimated mineral properties are physically reasonable is obtained by: (1) testing using synthetic data; and (2) comparison with published data.
After the detailed rock physics models have been built, we can test whether simplified models may be usefully applied, to either geophysical well log data or seismic AVO inversion data, to predict mineralogy for regional reservoir characterization studies.
Presentation Date: Tuesday, September 26, 2017
Start Time: 11:25 AM
Presentation Type: ORAL
Kiatrabile, T. (PTT Exploration & Production) | Noosri, R. (PTT Exploration & Production) | Hamdan, M. K. (PTT Exploration & Production) | Kusolsong, S. (PTT Exploration & Production) | Palviriyachote, S. (PTT Exploration & Production) | Suwatjanapornphong, S. (PTT Exploration & Production) | Rattanarujikorn, Y. (PTT Exploration & Production) | Sarisittitham, S. (PTT Exploration & Production) | Piyajunya, T. (PTT Exploration & Production) | Phonphetrassameekul, N. (PTT Exploration & Production) | Manai, T. (Schlumberger) | Adisornsupawat, K. (Schlumberger) | Mustapha, H. (Schlumberger) | Press, D. (Schlumberger)
Abstract The main objective of this paper is to present the assessment and methodology that would improve the tight oil recovery by hydraulic fracturing (HF) wells. The methodology is enabled by a fully integrated workflow orchestrating petro-physical log interpretation, static modelling, and dynamic modelling coupled with rock mechanics for an optimal fracturing design and mitigating the underlying risks. In the past, well placement in tight reservoirs and HF design were performed mostly based on available analogous data of offset wells using rock mechanics parameters such as stress magnitude and regional stress orientation to predict the fractures that would propagate through the reservoir in a certain location and well orientation, the stress/strain regime is one of the key parameters that plays an important role. It is also the key performance indicator for developing the tight oil reservoir with underlying complexities. The process is initiated by the conventional static modelling which involves structural framework construction, distributing the petro-physical characteristics subject to the well logs and other available subsurface data. The second step is to perform a history match of a derived dynamic model by honouring the observed data. This process helps in calibrating the model to be able to represent reservoir dynamic behavior. The results of the history matched model; i.e., reservoir pressure through time is the key input for the Mechanical Earth Model (MEM) in the next step. The MEM process starts with the construction of a 1D MEM using well log advanced scanner and rock mechanics properties from laboratory to represent the strength and elastic properties of the rock where existing wells have been penetrated into the reservoir layers. Hence, a coupled dynamic reservoir simulation with 3D geomechanical model will yield a realistic relationship between the current reservoir depletion state in terms of pressure and the current stress strain regime. This relationship is paramount for optimal location indentification of the fracturing wells and corresponding design together with an estimation of the subsequent recovery. Also, the rock mechanic simulation study would yield a comprehensive result with respect to the reservoir mechanical integrity while conducting the hydraulic fracturing operation to increase the well productivity. This integrated workflow is considered as the key step for tight oil reservoir development, and it can be expanded to unconventional resources for a better reservoir characterisation and reservoir development. The study was performed within close collaboration within the teams with comprehensive know-how sharing and exchange.
Zhang, Hao (Baker Hughes Incorporated) | Mendez, Freddy (Baker Hughes Incorporated) | Frost, Elton (Baker Hughes Incorporated) | McGlynn, Ian (Baker Hughes Incorporated) | Alarcon, Nora (Baker Hughes Incorporated) | Mezzatesta, Alberto (Baker Hughes Incorporated) | Quinn, Terry (Consultant) | Manning, Michael (Consultant)
The estimation of porosity, kerogen concentration, and mineral composition is an integral part of unconventional reservoir formation evaluation. Porosity and kerogen content are the main factors influencing the amount of hydrocarbon-in-place, while mineral composition affects hydraulic fracture generation and propagation. Unconventional resources such as shale plays are compositionally complex due to great variability in rock composition and post-depositional diagenetic processes. Consequently, a reliable method that integrates results from various logging tools and core analysis is needed to determine these key petrophysical properties.
Conventional well logs are typically acquired as a minimum logging program, providing geologists with the basic elements for tops identification and stratigraphic correlation. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by a minimum subset of minerals. In organic shale formations, these techniques often prove ineffective because conventional well logs are influenced to some degree by variations of mineralogy and porosity. Advanced geochemical logs, which are measurements that respond to capture and inelastic elemental composition of the rock and fluids using pulsed neutron technology, can help to understand this variability in mineralogy. This work introduces an inversion-based workflow based on probabilistic concepts to estimate total organic carbon (TOC), mineral concentrations, and porosity of shale formations using a combination of geochemical logs and conventional logs.
The workflow starts with the construction of a log-based deterministic mineral model including the most likely minerals based on available knowledge and core analyses. An iterative inversion process is then applied, based on the mineral model, to estimate mineral content and porosity in addition to considering formation complexity and data quality. Uncertainties derived for each logging tool along with borehole environmental factors are formally integrated into the solution. Validation of the proposed methodology is performed using actual field data sets. A field example is supplied from a Fayetteville shale play where the workflow was successfully implemented, along with a comparison with core measurements such as XRD, XRF, SEM, porosity and pyrolysis data. The comparison shows good agreement between TOC and mineralogy derived from logs and cores.
The proposed workflow integrating geochemical and conventional log measurements can reliably estimate the key petrophysical properties for unconventional reservoirs especially hydrocarbon-bearing shale. This method can be used to make decisions on optimum lateral placement.
Abstract This paper discusses a different approach to defining rock types and lithofacies performed for the Hollin formation located in the Palo Azul field of Ecuador. The study includes a spectrum of depositional environments, which significantly influences geometry, diagenesis, and quality of the Hollin reservoir. This work integrates lithofacies and petrophysical properties using well log data, core, and sedimentological analyses to define rock types. Sedimentological analyses were performed to describe existing cores, thin sections, and X-ray diffraction results. Flow units were identified using flow zone indicator (FZI) and reservoir quality index (RQI) methods. These units were classified as functions of flow capacity (K/Phi) based on capillary pressure (Pc) and other special lab analyses. Capillary pressure enabled the grouping of rock flow units in accordance with the K/Phi ratio, similar RQI, and irreducible water saturation (Swirr) values. These rock types (RT) were correlated with the lithofacies identified using sedimentological analysis. The transgressive Hollin formation sequence includes fluvial mid-grained sandstones with cross stratification, tidal mid- to fine-grained sandstones with mud drapes and organic matter, and marine glauconitic sandstones with/without calcareous cement. Integrated sedimentological and petrophysical analysis defined five rock types (RT1-RT5). RT1 and RT2 correspond to tidal quarztarenites and fluvial sandstones with few discontinuous clay laminae, high permeability, and high porosity values. RT3 includes tidal fine-grained sandstones with abundant clay and organic matter in the matrix, which decreases flow capacity. RT4 is characterized by very fine- to fine-cemented tidal sandstones in which the diagenetic events close the porosity and permeability. RT5 is a muddy sequence of tidal/fluvial environments, marine shales, and well-cemented glauconitic sandstones. These rocks present negligible permeability and low porosity. In conclusion, the reservoirs deposited in tidal bars and fluvial channels have major flow capacity and storage characteristics, whereas the rocks of the shallow marine and sand flat environments present poor reservoir quality. This integrated petrophysical and sedimentological work presents an alternative method for identifying rock types by using flow capacity and the integration of conventional core data, sedimentological analysis, petrographic and diagenetic description, capillary pressure, well logs, and reservoir information. The results from this method were incorporated in the geocellular model for reservoir simulation.
Reeder, Stacy Lynn (Schlumberger) | Kleinberg, Robert L. (Schlumberger) | Vissapragada, Badarinadh (Schlumberger) | Machlus, Malka (Schlumberger) | Herron, Michael M. (Schlumberger) | Burnham, Alan (American Oil Shale LLC) | Allix, Pierre (Total Exploration and Production)
Historically, well-logging and interpretation workflows have been developed mainly for use in porous and permeable reservoir formations and are not commonly used to evaluate source rocks or unconventional reservoirs. Instead, the evaluation of oil shales, such as the organicrich deposits of the Green River Formation, has relied primarily on expensive and inefficient core analyses, such as the Fischer assay, and simple log interpretation. With the potential oil equivalent in place exceeding a trillion barrels, there is a need for detailed characterization of these oil shale deposits using high-resolution well logs.
We have logged two Green River Formation wells using combinations of standard and advanced logging techniques. This program was supported by extensive core analysis, including Fischer assay and thorough mineralogical and chemical analyses. Methods of determining kerogen content from log responses were developed along with multiple methods of estimating a continuous log of formation-water salinity. We developed methods for quantitatively evaluating these Green River Formation oil shales by integrating standard logs with more advanced logging measurements including nuclear magnetic resonance, elemental capture and inelastic spectroscopy, and dielectric dispersion. The results and the petrophysically derived multimineral model are validated by the core measurements and then applied to a nearby well.
This paper was presented at the 11 th Offshore Mediterranean Conference and Exhibition in Ravenna, Italy, March 20-22, 2013. It was selected for presentation by OMC 2013 Programme Committee following review of information contained in the abstract submitted by the author(s). The Paper as presented at OMC 2013 has not been reviewed by the Programme Committee. ABSTRACT HTHP environments challenge formation testing tools, and even if some successful HT sampling and pressure jobs have been recorded in history, the combination of OBM, focused sampling technique, H 2 S and full downhole fluid analysis (DFA; composition, GOR, Fluorescence, fluid coloration, H 2 S) in real time, has never been attempted. This was due to the fact that the increase of temperature and pressure leads to a rapid decrease of signal quality in the downhole fluid analysis sensors. Additionally, the increased risk of tool failure at HTHP pushed the Operators towards the use of basics toolstrings when it came to Wireline Formation Testing (WFT), dramatically limiting the use of the most advanced DFA technologies in these conditions.
Kiatpadungkul, Wiriya (Schlumberger) | Daungkaew, Saifon (Schlumberger) | Chokthanyawat, Suchart (Schlumberger) | Promkhot, Soontorn (Schlumberger) | Ayan, Cosan (Schlumberger) | Houtzager, Johan Frederik (Pearl Oil (Thailand) Ltd) | Platt, Christopher J. (Pearl Oil (Thailand) Ltd) | Storer, Alexander James (Pearl Oil (Thailand) Ltd) | Tabmanee, Piyatad (Pearl Oil (Thailand) Ltd) | Panyarporn, Pantaporn (Pearl Oil (Thailand) Ltd) | Voradejviseskrai, Suttapan (Pearl Oil Thailand Ltd) | Limniyakul, Theeranun (Pearl Oil (Thailand) Ltd) | Last, Nick (Pearl Oil (Thailand) Ltd)
Abstract In Asia Pacific region, there are many thinly bedded reservoirs which are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sand bodies range from millimeters to tens of meters in thickness. Though the reservoirs are highly permeable, reservoir heterogeneity caused by silt and clay laminations affect recovery and sweep efficiency. The typical way to test such formations is to use full scale well testing, even for relatively thin zones. In the Gulf of Thailand (GoT), a Tubing Stem Test (TST) is widely used to test each individual zone for reservoir parameters. During a TST, quartz gauges are run on wireline and the selected zone is perforated. While wireline Formation Testers (FT) have also been increasingly used in the GoT for measuring formation pressure, mobility and collecting reservoir fluids, more advanced FT tools, e.g. dual packers and Downhole Fluid Analyzers (DFA) were recently introduced to test each zone to help defining reservoir characteristics in more detail. A single probe FT deployed for pretests and fluid sampling can be used to obtain transient data during the shut-in periods after sampling in relatively thin zones. The data from these Interval Pressure Transient Tests (IPTTs) can be used to interpret reservoir parameters such as vertical to horizontal permeability ratio and horizontal permeability. This paper discusses the uses of such smaller scale pressure transient data (single probe, dual packer formation testers) and full scale well testing using a simulation model and actual field data from the GoT. First, a single well simulation model is used to investigate the effects of thinly bedded shales at different scales on pressure transient data. The actual field data were then analyzed to obtain reservoir parameters and compared with core and PVT lab results. This paper also investigates the use of deconvolution applied to pressure transient tests of different scales to understand the effect of reservoir parameters using simulated and field data. Introduction Thinly Bedded Reservoirs in the Gulf of Thailand In the Tertiary Basins of the Gulf of Thailand and Northern Malay Basin, thinly bedded hydrocarbon sandstone reservoirs have been encountered in several geological settings. In the northern Gulf of Thailand, Kra Basin, subaqueous lacustrine fan delta sandstones of between 1 to 4 feet have developed as a result of episodic deposition. In the Southern part of the Pattani Basin adjacent to the Narathiwat High, thinly bedded reservoirs of less than 1 to 7 ft were deposited in marginal marine, tidally influence estuarine channel fills settings and also in more proximal fluvial crevasse splay deposits.
Abstract Traditionally, the Gulf of Thailand (GoT) has been known for high temperature, small borehole size, variable CO2, and highly compartmentalized reservoirs. In particular, it is a very challenging environment for Wireline Formation Testers (WFT). Owing to cost constraints, since the start of exploration and development campaigns in this area, usage of newer technologies has been highly selective. However, this has been changed significantly in the past few years where the right WFT technology has been applied to the right environment. This paper is the first to present a work process to derive clean fluid sampling in the very challenging environment of the GoT. Time per station used to collect downhole fluid samples using WFT has been a major concern for a costly offshore operation. In addition, borehole stability is also another factor limiting WFT time. Given the time constraint, collected fluid samples usually have high drilling mud filtrate contaminations, in the ranges of 25 to 85wt%, and have not been suitable for further laboratory analysis and field development purpose. Balancing between the time used for fluid sampling and the quality of the collected fluid samples is not a simple task to manage. This paper shares a successful story of downhole fluid sampling in exploration wells for one of the operators in the GoT. Instead of using a conventional probe with one Downhole Fluid Analyzer (DFA), the concentric shaped probe with two synchronized pump-out modules and two DFAs are used in this case. However, this is not as simple as other fields already presented in the literature because an unconsolidated sand character introduced complications into this sampling technique. Several attempts have been developed to make focused sampling work in these challenging environments. At the end, "Less than 5% OBM contaminated samples in oil reservoirs are successfully achieved in a timely manner." The average time used per each sampling station is approximately 30 minutes. This paper will also discuss the advantages and disadvantages for each technique applied and the final results. In addition, more improvements have been suggested to enhance this focused sample technology in more complex fluids, such as gas condensate reservoirs to make sure that less contaminated fluid sample can be collected in the limited time per station