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Results
Integrated Workflow for Reservoir Management in Mature Waterflooded Reservoir within a Complex Geological Environment: Gullfaks Case Study
Kareb, Ahmed (University of Houston, Houston) | Dindoruk, Birol (University of Houston, Houston) | Chiboub-Fellah, Abd Elaziz (IFP School, Paris) | Gareche, Mourad (University of Boumerdes, Boumerdes)
In the context of field development planning, the project workflow has to be outlined beforehand to ensure the most optimal and accurate outcomes within time limits. The workflow started by utilizing a G&G software, Petrel, to depict the rock type and fault distribution within the geological models by incorporating interpreted seismic data and well logs. This integrated approach facilitated a comprehensive understanding of the reservoir's structural and geological characteristics. Furthermore, standard geostatistical techniques applied in software generated property models that ensured alignment of permeability and porosity distribution with the corresponding well logs. Interpretation of production data, PVT, and SCAL served as the basis for initializing the model using a reservoir simulator, Intersect, as a dynamic flow simulator. The accuracy and reliability of the model were ensured through quality checks, which include volume estimate comparison starting with equilibrium runs. Additionally, sensitivity analysis was performed by adjusting model parameters to achieve a history match and align simulated results with actual reservoir behavior in various ways. The calibrated model explored using a high-resolution simulator for high accuracy and more options for development strategies such as infill wells (horizontal and vertical), well conversions, water shut-off (zonal isolation and selective perforation), stimulation operations, and ESP systems in order to optimize reservoir performance and maximize production while improving sweep efficiency. Lastly, economic evaluation based on net present value (NPV) analysis considered techno-economic factors to identify the most suitable development strategy that balanced technical feasibility with economic viability.
- North America > United States (0.94)
- Europe > Norway > North Sea > Northern North Sea (0.70)
- Geology > Rock Type (0.88)
- Geology > Geological Subdiscipline (0.68)
- Geology > Structural Geology > Fault (0.47)
- Geophysics > Borehole Geophysics (0.88)
- Geophysics > Seismic Surveying (0.54)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- (7 more...)
- Information Technology > Software (0.50)
- Information Technology > Modeling & Simulation (0.47)
- Information Technology > Software Engineering (0.41)
Abstract Understanding the current pressure of unperforated gas reservoirs is critical for field development. Perforation of depleted reservoirs results in low hydrocarbon production, unwanted water production, or no flow. Thus, a through-casing well-based reservoir pressure surveillance is essential before perforating the target zones to assess if pressure depletion occurs due to the production of connected reservoirs from offset wells. Pulsed neutron (PN) logging in wells filled with produced gas can reduce some measurements’ formation sensitivity. For example, ratio-based measurements required for gas saturation and pressure depletion analysis using inelastic gamma-ray count rates can be particularly affected when wellbores are gas-filled. As a solution, a sleeved-PN well logging technique was developed to delineate pressure depletion in cased gas-producing wells. The pulsed neutron source and gamma-ray detectors of the sleeved-PN tool are covered with a layer of hydrogen-rich material, such as fiberglass, thereby improving the measurements’ formation sensitivity compared to ones from a regular PN tool in a gas-filled wellbore. The pressure depletion evaluation workflow includes nuclear measurements from a sleeved-PN tool, the Monte Carlo N-Particle (MCNP) method-based forward modeling of tool responses, and an iterative analysis algorithm. We deployed a sleeved-PN logging tool in a gas condensate-producing well in the North Sea. The well was produced from deeper Triassic sands with a section of Jurassic sand bodies above which are not perforated and of uncertain depletion. During PN logging, the wellbore was filled with gas from the deeper perforated sands. Pressure depletion analysis was performed using three key measurements: inelastic and capture gamma-ray count rate ratios and a macroscopic thermal neutron capture cross-section (formation sigma). Each measurement revealed distinctive characteristics; therefore, comparing these measurements integrated with forward modeling responses allowed for determining reservoir pressure depletion. Accurate MCNP modeling was a crucial factor in the pressure depletion evaluation. Furthermore, the current in-situ gas density estimation was based on a series of MCNP modeling results. An iterative method of comparing measured and modeled data with reference to original water saturation was used to calculate the current gas density. The analysis showed indications of pressure depletion in the lower sand section but not in the upper formation. Ratio-based PN measurements were effective in indicating depletion. Formation sigma was practical to compute the current water saturation as it is relatively insensitive to changes in reservoir pressure and gas density. Evaluating pressure depletion before perforating sands in gas-producing wells, especially when gas is present in the borehole, is challenging. However, advances in PN logging technique and an innovative data analysis method enabled cost-effective monitoring of formation pressure in a cased-hole environment and enhanced confidence in reservoir management decision-making.
- North America > United States (0.96)
- Europe > United Kingdom > North Sea (0.84)
- Europe > Norway > North Sea (0.61)
- (2 more...)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > P111 > Block 22/25a > Culzean Field (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Rawdatain Basin > Upper Burgan Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
The Vital Role of Advanced Cutting Analysis in Unconventional Reservoir Characterization
Fahmy, Mahmoud Fawzy (Kuwait Oil Company) | Nguyen, Kim Long (Kuwait Oil Company) | Dasma, Mohammed (Kuwait Oil Company) | Al-Mutairi, Nami (Kuwait Oil Company) | Al-Morakhi, Rasha (Kuwait Oil Company) | Alkandari, Abrar Yousef (Kuwait Oil Company) | Quttainah, Riyad (Kuwait Oil Company) | Ousididene, Karim (Excellence Logging) | Moustafa, Ahmed (Excellence Logging) | EL Masry, Mohab (Excellence Logging) | Magnier, Caroline (Excellence Logging) | Sharma, Sachin (Excellence Logging)
Abstract Advanced Cutting Analysis technique has been widely used in the industry to assist drilling operations as well as providing support in formation evaluation. Recently, alongside with the speedy development of Najmah Kerogen unconventional reservoir in Kuwait, the technique has demonstrated its vital role resulting in significant cost saving, and reliable measurements that could be used to replace other expensive evaluations from cores or open-hole logs. The Advanced Cutting Analysis was applied in Well-H drilled recently in Kra Al-Maru field, West Kuwait (Fig. 1) that comprised of different technologies: X-ray diffractometry (XRD) for mineralogy, X-ray fluorescence (XRF) for rock chemical composition, Total Organic Carbon (TOC) analysis, and Pyrolysis for source rock characterization. The XRD-XRF technology was popular in the industry, and it could be acquired from core or open-hole log data. In this study, XRD-XRF was conducted on cutting samples. In order to prove the efficiency of this technology applied on cuttings and its potential use as alternative method to support unconventional reservoir characterization in the future, the result was validated with elemental spectroscopy wireline logs. This paper presents the workflow used for analyzing and integrating multidisciplinary datasets in order to develop an alternative method for unconventional reservoir characterization that included the use of surface advanced cutting and fluid analysis. The aim is to: Reduce the uncertainty of production sustainability and proper well planning of the tight fractured carbonate unconventional reservoir. Build up alternative reservoir assessment model using advanced cuttings analysis in HPHT wells, slim hole, limited logging, etc. Evaluate mineralogical composition of the rock including the formation brittleness index, which helps on the post drilling fracturing strategy. Elemental Gamma Ray as cost effective for geo-monitoring and well placement assistance as well as eliminate the risk associated to down hole effects such as: hole geometry, vibration, high mud weight used while drilling, rock mechanical stress, high temperature and pressure can lead to lost signal.
- North America > United States > Texas (1.00)
- Asia > Middle East > Kuwait > Jafra Governorate (0.25)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.95)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (3 more...)
- Information Technology > Artificial Intelligence (0.68)
- Information Technology > Data Science (0.46)
Evaluating the Potential of the World-Class Najmah Unconventional Reservoir: Collaborative Approach to Design a Pilot Well
Al-Bahar, Mohammad (Kuwait Oil Company) | Al-Adwani, Talal (Kuwait Oil Company) | Suresh, Vandana (Kuwait Oil Company) | Al-Ostad, Nejoud (Kuwait Oil Company) | Al-Rukaibi, Anas (Kuwait Oil Company) | Al-Najjar, Abrar (Kuwait Oil Company) | Caicedo, Vladimir (DeGolyer and MacNaughton) | Robinson, Gary (DeGolyer and MacNaughton) | He, Ting (DeGolyer and MacNaughton) | Johnston, Robert (DeGolyer and MacNaughton) | Hosseinpour-Zonoozi, Nima (DeGolyer and MacNaughton)
Abstract The distinctive nature of the unconventional resources in the Najmah formation in The State of Kuwait poses unique challenges that must be overcome to achieve economic development. The Najmah potential has been characterized with large detail in several asset areas of the country, however, a regional, country-wide Play Fairway Assessment was carried out to high-grade those areas that could constitute the sweet spot for focusing on Pilot Well Design and Resource Evaluation. 1D and 3D Mechanical Earth Models were also developed to fine-tune the proposed sweet spot area and aid in the pilot wellbore design evaluation. The objective of the Play Fairway Analysis study was to carry out a thorough integration of Geology, Geophysics, Petrophysics, Geomechanics and Drilling data to produce an evaluation throughout the state of Kuwait. In this study, we developed and implemented an Unconventional Evaluation Workflow with the objectives of assessing a recommended sweet spot area and planning a pilot program to enable testing of the unconventional resource potential in Kuwait. This work compiles the results obtained from the Play Fairway Analysis (PFA) and the 1D & 3D MEM with particular emphasis on seismic-driven modeling, integrating them into the selection of a "sweet spot" area where a pilot multi-stage horizontal fractured well (MSHFW) is proposed as the completion methodology for the world-class Najmah Shale Unconventional reservoir. A seismic-well model was selected as the basis for mechanical, and petrophysical properties in the final geological grids. The Eagle Ford shale formation in the Gulf Coast basin of south Texas was designated as the analog Unconventional reservoir for the Najmah Shale, as it has similarities in lithology, clay content, TOC volume fraction, reservoir depth, formation temperature and initial reservoir pressure. The novelty of this study was to integrate to the best extent the available multidisciplinary data and propose a pilot unconventional well program that gives the best chance of success to evaluate the Najmah Unconventional potential. The Najmah reservoir poses unique and challenging characteristics that require an out-of-the-box approach. The pilot well design focused on incorporating existing, industry-wide proved, and available technology. The proposed MSHFW completion incorporates current industry trends and best practices regarding stage spacing, fluid selection, proppant selection, and pumping schedules. The proposed completion design was also influenced by the need to compare and contrast with production test results from established analogous unconventional plays.
- North America > United States > Texas (1.00)
- Asia > Middle East > Kuwait (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.96)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (11 more...)
A Machine Learning Approach Performed on New Technology for Images in Oil-Based Mud for Advanced Electro-Facies Analysis – A Case Study from the Norwegian Sea
Ahmad, Sayyid (Halliburton) | Mirza, Dler (AkerBP ASA) | Waage, Henrik (AkerBP ASA) | Gales, Robert (Halliburton) | Aarseth, Nils Andre (AkerBP ASA) | Engelman, Bob (Halliburton) | Barrett, Peter (Halliburton) | Jambunathan, Venkat (Halliburton)
ABSTRACT Exploration projects often require high quality image data acquired in oil-based mud filled boreholes to evaluate thin laminated sandy shale formations. The introduction of a new oil based electrical imager technology allows detailed facies analysis and identification of open and closed fractures. Simple cutoff methods are widely used for lithofacies identification and facies classification, which can be a time-consuming task. However, this work presents an automated machine learning based electro-facies classification using a combination of resistivity and permittivity dominated image log data integrated with other conventional data. An advanced dataset was acquired in a near vertical well drilled in the Norwegian North Sea, to test the hydrocarbon potential in reservoirs of Sinemurian to Callovian age in an overall transgressive succession ranging from coastal/lower delta plain, lower shoreface to offshore deposits. In addition, the prospect was located on a rotated fault block heavily influenced by internal faulting. Machine learning workflows are created after loading all images, conventional log data, surface seismic and VSP (vertical seismic profile) data. Before running any facies prediction, the advanced workflow encompasses four pre-conditioning steps for data standardization; 1) data-pre-processing for speed correction, button/pad repair and alignment if needed, 2) data reduction by features and instance selection as well as dimensional reduction, 3) parametric testing to see if the available data follows rules of normality, and 4) normalization of data is performed if required. After standardizing the data, different classifiers are tested iteratively for facies prediction. Each step of the machine learning from data conditioning to facies prediction is constrained by consideration of the sedimentological and depositional environment. The resultant electro-facies were compared with lithofacies interpreted manually by using core and conventional log data acquired in the same well. In addition to the machine learning based facies classification, fractures were classified into open and closed fractures by interpreting the resistivity and permittivity image components. After iterating the classifiers, six electro-facies were created and discussed based on K-means clustering and self-organizing maps. By integrating high-resolution image log texture and conventional well log patterns different depositional environments were linked to the electro-facies identified. Facies 1, 2, and 3 were found to be sand-dominated facies, which comprise mainly transgressive to regressive sands followed by the deposition of aggrading sandy packages deposited in mixed-energy, coastal-deltaic settings during the Lower-to-Middle Jurassic, facies 4 was found to be a silt dominated heterolithics facies, which represent a transitional environment of deposition. Facies 5 and 6 were found to be mudstone-dominated facies, which possibly represent local or regional transgressive events during local or regional flooding events. The classified electro-facies work is integrated with surface seismic and VSP and can potentially be used for future input to describe lateral and vertical rock distribution patterns and for improving static and dynamic reservoir models for enhanced reservoir understanding. In addition, fracture interpretation with permittivity dominated images is proved and can be used to further improve completion design and well productivity.
- North America > United States (1.00)
- Europe > Norway > North Sea (0.54)
- Phanerozoic > Mesozoic > Jurassic > Middle Jurassic (0.54)
- Phanerozoic > Mesozoic > Jurassic > Lower Jurassic (0.34)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Garoupa Cluster > Namorado Field (0.99)
- South America > Brazil > Campos Basin (0.99)
- Europe > Norway > Norwegian Sea > Åre Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Operationalisation of Advanced Mud Gas Logging in Development Drilling: Examples from the Recent HPHT Infill Campaign in the Central North Sea
Kolonic, Sadat (Shell Exploration & Production) | Pisharat, Maneesh (SLB) | Schachner, Josef (Shell Exploration & Production) | Shipp, Richard (Shell Exploration & Production) | Bosscher, Hemmo (Shell Exploration & Production) | van Bergen, Pim (Shell Exploration & Production) | Podlaha, Olaf (Shell Exploration & Production)
ABSTRACT Standard Mud Gas (SMG) logging has served the drilling engineering discipline principally in executing safe well delivery. Additional subsurface insights are often considered less important when commissioning this service for development wells. Consequently, SMG remains routine despite the advances in quantifiable Advanced Mud Gas (AMG) logging capability. Such advances make it more operationally feasible to deploy AMG and thereby markedly enhance the acquired subsurface insights. This was demonstrated during a recent High Pressure, High Temperature (HPHT) infill campaign in the Central North Sea (CNS). Wells targeting deep Jurassic formations have used AMG technology for continuous compositional analysis while drilling. Mud gas is the only measurement to provide a continuous record of reservoir fluid composition, a fact that seems underappreciated in the industry. For a mature field experiencing production-related changes to reservoir fluid, the main objective of collecting AMG data is to aid early assessment of downhole hydrocarbon variability. For example, identifying reservoir tops, fluid dissimilarities, and an independent saturation flag is critical operational information especially while using Drilling-In-Liner (DIL) and in the absence of Logging-While-Drilling (LWD) data. These insights help to guide decisions on completion strategy and logging behind casing, which in turn aids rig time optimisation and offsets the deployment costs. Post-drill systematic integration with other geochemistry data (e.g., fluid compositions, gas isotopes, mineralogy, and kerogen compositions), wellsite geology (shows, lithology), and independent petrophysical techniques (such as triple combo) enables the identification of possible missed pay zones. Once ‘field’ calibrated, the AMG data increases fluid phase interpretation confidence in support of near-time operational decisions and overall reservoir management. An example is the confirmation of new flow unit contributors to perforations for future well interventions/abandonment consideration. Further value upside and differentiation are achieved by collecting the AMG data across the overburden chalk common to Jurassic fields in the CNS, providing for the first-time, in-field granularity on chalk fluid facies, reservoir architecture, and connectivity. Mud gas technology offers an optimised solution in terms of viability (cost), feasibility (technical deployment), and value of information (pay and phase) (Malik et al., 2020). The benefits of utilizing this technology are especially clear in both HPHT, and conventional field settings, making it a highly recommended tool for routine deployment. Looking to the future, the use of quantitative mud gas records can enhance our comprehension of the vertical and lateral fluid distribution in depleted and decommissioned petroleum fields and Carbon capture, utilisation and storage (CCUS) sites. This technology can be utilized to establish benchmarks and monitor changes over time, providing crucial information for integrity monitoring.
- North America > United States (1.00)
- Europe > North Sea (1.00)
- Europe > United Kingdom > North Sea (0.84)
- (3 more...)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.95)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- North America > Canada (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/16 > Fulmar Field > Fulmar Formation (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/11b > Fulmar Field > Fulmar Formation (0.98)
- (8 more...)
Un-Realize Application of LWD Multipole Sonic Tool for Evaluating Cement Quality: Optimizing the Well Operation in a Highly Deviated North Kuwait Deep Jurassic Well Case Study
Al-Mutawa, Majdi (Kuwait Oil Company) | Saffar, Ali Hussein (Kuwait Oil Company) | Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Al-Otaibi, Fahad Barrak (Kuwait Oil Company) | Abdulmohsen, Naser Bader (Kuwait Oil Company) | Ragaey, Mohsen Mohammed (Kuwait Oil Company) | Kumar, Joshi Girija (Kuwait Oil Company) | Alomar, Abdulrahman Ahmad (Kuwait Oil Company) | Tiwary, Devendra Nath (Kuwait Oil Company) | Pasaribu, Ihsan Taufik (Schlumberger) | Al-Bannai, Khaled (Schlumberger) | Kho, Djisan (Schlumberger)
Abstract Cement quality is an important well integrity consideration to ensure proper hydraulic sealing. Traditionally, wireline cement bond logs have been used extensively in the Jurassic formation of North Kuwait. The case study well presented in this paper had an 80° inclination and 3,000 ft of a 6-in. open hole, which has remained opened for quite some time. Cement evaluation was required inside the 7 5/8-in liner to determine the cement quality behind the liner and integrity of liner shoe. This information is important for achieving a successful of multistage completion for the producing interval in the 6-in open hole. The target interval had a vertical depth greater than 14,000ft from mean-sea level with a well deviation more than 80°. Four operational days were required to run drill pipe conveyance of conventional cement evaluation wireline tools. This operation would have exposed the 2,500ft of open hole to potentially collapsing situation due to the time dependence of the wellbore stability. The capability of logging-while-drilling (LWD) multipole sonic tool for evaluating the cement quality was considered, as there was plan to acquire open hole log data using LWD technology, which included the LWD multipole sonic tool. While running in the hole to the open hole section, the LWD multipole sonic tool can acquire sonic-based cement evaluation data inside of the 7 5/8-in liner. This operating method consumes no rig time while obtaining the well integrity information. This paper presents the case study, along with the LWD multipole sonic tool theory for measuring cement bond quality index, operation preparation, and the results of the data acquisition.
- Asia > Middle East > Kuwait (0.72)
- North America > United States (0.69)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Well Drilling > Casing and Cementing > Cement and bond evaluation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Summary Estimating a transition between rock types from well logs using traditional methods can be challenging and time-consuming. Developing new approaches to improving the quality of the estimation as well as saving time becomes necessary. This paper presents a new methodology that uses elements of chaos theory to evaluate the variability of well logs to identify rock layers. Four different parameters that quantify chaos were used in the present study: fractal correlation dimension, sample entropy, Hurst exponent, and Lyapunov exponent. Each of them describes a different property of a well log. The method presented in this paper uses all of them together for an extensive characterization of well log irregularities. The study was carried out on a set of 68 well logs from six wells in the Pluto gas field (Australia). The logs were divided into segments of 25 m. A computer program was written to calculate the chaos parameter values of each interval. The parameters were then analyzed statistically. Hierarchical methods and k-means clustering were used to create dendrograms and clusters. The statistical analysis of the results has shown that the well log variability can be used to successfully differentiate rock formations by showing which intervals on a log are similar. In addition, the intervals that correspond to Mungaroo sandstones, which are the reservoir rock of the Pluto gas field, were particularly distinguished from other parts of the log. Therefore, the presented methodology could prove useful to estimate zones of interest in terms of hydrocarbon potential. The presented algorithm accounts for the variability of the well log readings, not the log values themselves. It does not point exactly to a depth where rock layers interface, but it rather allows similar (in terms of irregularities), consecutive intervals to be grouped together. Based on that, one can draw a conclusion that a lithology differs between groups of intervals.
- Oceania > Australia > Western Australia > North West Shelf (1.00)
- North America > United States (1.00)
- Oceania > Australia > Western Australia > Burrup Peninsula > North West Shelf (0.70)
- Phanerozoic > Mesozoic > Jurassic (0.68)
- Phanerozoic > Cenozoic (0.68)
- Phanerozoic > Mesozoic > Cretaceous (0.47)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.69)
- Oceania > Australia > Western Australia > North West Shelf > Muderong Shale Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Mungaroo Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > Rankin Platform > Greater Gorgon Development Area > Block WA-268-P > Greater Gorgon Field > Gorgon Field (0.99)
- (10 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract The presence of halite cement is a little appreciated problem in petrophysical interpretation. Yet halite is common as a late diagenetic cementing phase associated with high salinity formation water and is recognized in many of the world's major petroleum basins. Undetected halite cement leads to a significant overestimation of porosity and permeability during petrophysical interpretation. However, halite cement does not have a unique signature on electric logs and is often not represented in core samples. Current best logging practices are inadequate for the quantification of halite cement. Open hole sigma is a recommended logging solution. Scanning Electron Microscopy with Energy Dispersive Spectroscopy can detect halite. This is a rock imaging technique, performed on either cuttings or core. The images can distinguish between layered depositional halite and pore-filling diagenetic halite cement. Occurrences of non-authigenic halite, precipitated as the rock sample is brought to the surface, have a high surface area and are easily removed by sample cleaning. Conventional core analysis can both identify and quantify halite cement. However standard core cleaning methods operate on the premise that all halite is non-authigenic and thus intentionally remove it. Best practice core handling, processing and testing protocols must be followed and, because halite cement is commonly patchy and discontinuous, the core cleaning and drying study must comprise a large number of plugs. Oil-based mud must be used to cut the core. The effects on porosity and permeability of halite cement can be understood with reference to pore and halite size distributions. Halite cement in sandstones occurs as intergranular pore-occluding cement and is observed most commonly in ~5p.u. layers just a few meters thick. These layers have the same density and neutron log responses as a ~8-12p.u. sandstone filled with gas or light hydrocarbons. Detailed sample-bysample log interpretation in the context of the regional geology is the only way to correctly identify these features. Halite cement is usually found best developed in the cleanest and thickest parts of the reservoir. It most commonly occurs in terrigenous clastic sediments. Proximity to bedded salt is the critical factor. Case studies from the North Sea, the Berkine Basin, the West African PreSalt and East Siberia are discussed.
- North America > United States (1.00)
- Europe (1.00)
- Africa > Middle East > Algeria > Eastern Algeria (0.25)
- Proterozoic (0.68)
- Phanerozoic > Paleozoic (0.68)
- Phanerozoic > Mesozoic > Jurassic (0.46)
- Geology > Mineral > Halide > Halite (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.58)
- North America > United States > Michigan > Michigan Basin (0.99)
- North America > United States > Gulf of Mexico > Norphlet Formation (0.99)
- Asia > Russia > Siberian Federal District > Irkutsk Oblast > Kataganskiy District > East Siberian Basin > Nepa-Botuoba Basin > Verhnechonskoye Field (0.99)
- (15 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
During well planning, drillers and petrophysicists have different principle objectives. The petrophysicist’s aim is to acquire critical well data, but this can lead to increased operational risk. The driller is focused on optimizing the well design, which can result in compromised data quality. In extreme cases, the impact of well design on petrophysical data can lead to erroneous post-well results that impact the entire value-chain assessment and decision making toward field development. This paper presents a case study from an Upper Jurassic reservoir in the Norwegian Sea where well design significantly impacted reservoir characterization. Three wells (exploration, appraisal, and geopilot) are compared to demonstrate the impact of overbalanced drilling on both log and core data. Implications for reservoir quality assessment and volume estimates are discussed. Extensive data collection was initially carried out in both exploration and appraisal wells, including full sets of logging while drilling (LWD), wireline logging, fluid sampling, and extensive coring. Both wells were drilled with considerable overbalanced mud weights due to the risk of overpressured reservoirs in the region. The log data were subsequently corrected for significant mud-filtration and fines invasion, with calibration to core measurements guiding the interpretation. A thorough investigation of core material raised suspicion that there could also be significant adverse effects on core properties resulting from overbalanced drilling. The implications were so significant for the reservoir volume that a strategic decision was made to drill a geopilot well close to the initial exploration well prior to field development drilling. The well was drilled 6 years after the initial exploration phase with considerably lower overbalance. Extensive well data, including one core, were acquired. The recovered core was crucial in order to compare the reservoir properties for comparable facies between all three wells. The results from the core demonstrate distinctly different rock quality characteristics, especially at the high end of the reservoir quality spectrum. Results of the core study confirmed the initial hypothesis that overbalanced drilling had significantly impacted the properties of the core and well logs. This study shows how well design adversely affected petrophysical measurements and how errors in these data compromised geological and reservoir models, leading to a suboptimal field development plan that eroded significant value. This example provides a case study that can be used to improve well designs so that petrophysicists and drillers can both be part of the same value creation result.
- North America > United States (1.00)
- Asia (0.68)
- Europe > United Kingdom > North Sea (0.46)
- Europe > Norway > North Sea (0.46)
- Geology > Sedimentary Geology (1.00)
- Geology > Mineral (1.00)
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- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7a > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3b > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3a > Brae Field > Brae Formation (0.99)
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