Net-to-gross Research Articles

Optimizing reservoir characterization: insights from integrated data analysis

The Onshore Hydrocarbon prospectivity of the Niger Delta X-field is examined through the integration of 3D seismic and recorded information from well log data. Probable reservoirs of hydrocarbon-bearing were delineated to tackle the non-uniqueness in the identification of hydrocarbon quantity of concern. Three significant faulting patterns or systems were delineated and their architectural attributes depict a typical Niger Delta embedded anticlinal structural pattern. The study field exhibited both synthetic and antithetic structures, hence only fault on delineated reservoirs was used for structural modeling. All well locations were sited within the fault-supported synthetic and anticlinal structures and the static characteristics within the well coordinates were analyzed through petrophysical assessment. Depicted reservoir sands show low gamma ray readings, low volume of shale, considerate hydrocarbon saturation and low water saturation. The established petrophysical models showed a better net-to-gross (NTG) ratio, for the entire delineated reservoir units. This has contributed to the assessment of hydrocarbon-bearing reservoir units before employing the strategy for field development scenario, in order to eliminate dry hole drilling campaign. These will contribute to the reduction of operational costs, having delineated the accurate geometry and petrophysical model of hydrocarbon reservoir units.

Exploration breakthrough and factors for enrichment and high-yield of hydrocarbons in ultra-deep clastic rocks in Linhe Depression, Hetao Basin, NW China

Based on drilling and logging data, as well as geological experiments, the geological characteristics and factors controlling high-yield and enrichment of hydrocarbons in ultra-deep clastic rocks in the Linhe Depression, Hetao Basin, are studied. The results are obtained in four aspects. First, the inland saline lacustrine high-quality source rocks developed in the Paleogene in the Linhe Depression have the characteristics of early maturity, early expulsion, high hydrocarbon yield, and continuous and efficient hydrocarbon generation, providing an important resource basis for the formation of ultra-high pressure and high-yield reservoirs. Second, the weak compaction, early charging, and weak cementation for pore-preserving, together with the ultra-high pressure for pore-preserving and fracture expansion to improve the permeability, leads to the development of high-quality reservoirs with medium porosity (greater than 15%) and medium permeability (up to 226×10−3 μm2) in the ultra-deep strata (deeper than 6 500 m), which represents a greatly expanded space for oil and gas exploration. Third, the Linhe Formation adjacent to the trough exhibits a low net-to-gross (NTG) and good reservoir-caprock assemblage, and it is overlaid by very thick high-quality mudstone caprock, which are conducive to the continuous and efficient hydrocarbon generation and pressurization and the formation of ultra-high pressure oil and gas reservoirs. Fourth, the most favorable targets for ultra-deep exploration are the zones adjacent to the hydrocarbon generating center of the Paleogene Linhe Formation and with good tectonic setting and structural traps, mainly including the Xinglong faulted structural zone and the Nalinhu faulted buried-hill zone. The significant breakthrough of ultra-deep oil and gas exploration in the Linhe Depression reveals the good potential of ultra-deep clastic rocks in this area, and provides valuable reference for oil and gas exploration of ultra-deep clastic rocks in other areas.

Seismic net-to-gross estimation for a geologic model update: A case study from a turbidite lobe reservoir in the deepwater of the Niger Delta

Geologic model updates are routinely performed in mature fields to obtain improved descriptions of facies distributions and reservoir properties such as volume of shale, net to gross (NTG), and porosity, for better understanding of the static and dynamic behaviors of reservoirs for effective well placement, improved production, and monitoring. A simple but integrated seismic NTG estimation approach, using detuned seismic amplitudes is used in guiding NTG modeling during the geologic model update of a thin turbidite lobe reservoir in a mature oil field in the deep offshore Niger Delta. The objective is to address NTG overestimation and gross rock volume (GRV) uncertainty in a previous model arising from seismic amplitude tuning effects. A seismic NTG approach is chosen relative to sophisticated deterministic or stochastic inversion techniques to avoid tuning effects, which usually bias NTG estimates in thin turbidite reservoirs. The primary data set is a 2019 reprocessed prestack depth-migrated (PSDM) seismic data vintage, which had better resolution, higher signal-to-noise ratio, and more appropriate angle-stack apertures for amplitude variation with angle fidelity, than the older 2011 PSDM seismic data that are used in the previous geologic model. The methodology involved rock-physics analysis, seismic data quality checks (QCs), tuned area determination, detuning of composite seismic amplitudes of the top and base reservoir, and their direct calibration to NTG at wells. Good correlations are obtained between the detuned composite seismic amplitudes and NTG at wells. The seismic NTG map shows good calibrations at wells and provides a robust trend for net sand modeling in the oil pool and aquifer. Static model QCs and dynamic simulations prove that the seismic NTG attribute addressed the GRV uncertainty in the earlier model, thus giving confidence for using the updated model for the planning and geosteering of infill wells, sand completions, reservoir monitoring, and production.

Uncertainty Study Aids Development-Plan Optimization in Deepwater Gulf of Mexico

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32622, “Development-Plan Optimization and Uncertainty Study in a Major Deepwater Field in the US Gulf of Mexico,” by Mohsen Rezaveisi, SPE, Jennifer L. Campbell, and Paula L. Wigley, Woodside Energy Group, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. _ This paper describes development-plan optimization and a probabilistic uncertainty study using Latin hypercube experimental design constrained to production performance in Lower Miocene (LM) reservoirs of the deepwater Gulf of Mexico Shenzi Field. The purpose of the development-plan optimization was to identify, rank, and characterize future development opportunities (i.e., infills and injectors) in the LM reservoirs to arrest field decline. The study uses history-matched dynamic simulation models. Introduction The Shenzi discovery is approximately 122 miles off the coast of Louisiana in a water column approximately 4,400 ft deep (Fig. 1). This part of the field is a partially filled three-way closure against a salt-cored anticline. The discovery includes four main sand units (A, B, C, and D) that exhibit various degrees of hydraulic connectivity based on pressure data and production history. The area of interest in the current study is the Eastern part of the field. Static Model Build The geomodel covering the area of interest was built from two seismically interpreted horizons and approximately 180 faults. The model is subdivided into 13 zones using well-based true stratigraphic thickness maps. The average cell height is 2–3.5 ft thick with heterolithics driving the lower end of the range. Sequential indicator simulation was used to populate facies using well-based net sand trend maps by zone. In zones with evidence of channelization, a second nested facies model was used to build channels into the model. Shenzi East reservoir properties are good because of the high-quality sand deposited in the field. Lower reservoirs (C and D) have slightly more depositional complexity because of the varying paleotopography and a lower average net-to-gross (NTG) of approximately 53%. Upper reservoirs (A and B) had a larger sediment supply and were more continuously deposited, which resulted in a larger average NTG of approximately 67%. Dynamic Model History Matching The Shenzi East reservoir has been on production since March 2009, providing abundant production data for history matching. Of seven producers, six are still active, and the reservoir also features three water injectors. Producers and injectors are identified with letters P and I, respectively, followed by well numbers. Well P7 was drilled after 6 months of production from other producers; formation pressure data showing reservoir depletion are available for history matching. The water injectors were drilled in 2012–2013, but only two have formation pressure testing data available. Well P1 was completed in all sands; Wells P2, P3, and P6 were completed in three sands (D, C, and B); and the rest of the producers were completed in two sands (D and C). Production is commingled in all producers, resulting in allocation uncertainties between sands. Water production has been observed in five wells, with the current water cut in the range of 35–65%. The two most updip wells, P1 and P7, are still producing at zero water cut.

Combined synchronous simulation of discrete and continuous variables under high net-to-gross ratio reservoir

The Triassic TIII oil group in the Sangtamu oil field in the Tarim Basin is formed by multiple phases of channels cutting and superimposing one another, and the net-to-gross (NTG) ratio can exceed 90%. Strong heterogeneity exists in the spatial storage and seepage features of the sand body within the channel, causing significant uncertainty in the 3D geological modeling of the reservoir. In order to delicately characterize the reservoir heterogeneity within the channel in its various phases, this paper proposes a facies modeling method based on the deposition process. It includes a strategy of joint synchronous simulation of discrete facies and continuous physical property variables, fused trend body-constrained modeling established by the internal variation characteristics of single-phase channel sand, and an increase in channel phases to meet high NTG ratio reservoir conditions. In this process, the object-based method and sequential gaussian simulation method are both used to simulate step-by-step the 3D geological model of the facies and physical properties of different phase channels, respectively. The results show that 61 small sand bodies compose the results of the established 3D geological model, and the physical simulation results reflect the characteristics of physical changes inside the channel at different phases. The model has been verified by vacuate wells validation with a compliance rate of 97.4%, and the method reduces the model's multiple solutions and uncertainties while offering a new practical method for modeling complex fluvial facies reservoirs.

Improved Understanding of Minor Reservoirs Optimizes Full-Field Productivity

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21225, “Defining Heterogeneity and Compartmentalization Predictions of Minor Reservoirs in Fluvial Environments: Geological and Dynamic Context,” by Nur Azah Zulkifli, Lisa C. Chisholm, and Amy M.M. Yusoff, Petronas, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ Reservoirs in the MN field offshore Malaysia consist of predominantly fluvial delta deposits. Several modeling studies have been performed for major reservoirs. After more than 20 years of production, a project for minor reservoirs has been created. The primary objective of this study was to improve the understanding of the uncertainties affecting well performance and reservoir connectivity and to identify potential infill opportunities. Introduction From the initial analysis of a 2017 full-field review (FFR), the team decided that a detailed subsurface evaluation was necessary. This study was completed with the integration of subsurface data to ensure that hydrocarbon volume and geological knowledge have been calibrated with production performance. The field is 160 km north-northeast offshore peninsular Malaysia in a water depth of 69 m. This field is divided into five areas: Main, West, North, South, and Southwest. The depositional environment of this field is fluvial coastal plain and consists of multistacked oil and gas reservoirs with an average net thickness of 2–20 m, interbedded with shale and coal in a coastal plain setting. Geological Concept and Overview Reservoir X is one of 26 major and minor hydrocarbon-bearing units in the field. Twenty-two minor reservoirs were analyzed for the FFR with an integrated study work flow. Geological analysis concluded that these reservoirs were deposited in a fluvial environment consisting of meandering channels, point bars, overbanks, and abandoned channel-sand mouth bars with deltaic influence (Fig. 1). Seismic data have been used extensively to tackle key uncertainties with either quantitative or qualitative approaches, depending on the seismic detectability limit of the reservoir. The use of seismic in this case was challenging because seismic attributes are not optimal and mostly are used as soft data guided by primary well data. Additionally, several reservoirs required stratigraphic compartmentalization to be introduced. Heterogeneities in the Fluvial Environment Capturing and preserving the different level of heterogeneities was complex because of varied data resolution, grid definitions, and hierarchies of impact. This field has relatively large net-to-gross (NTG) ranges from 20 to 98% with individual channel width averaging from 20 to 100 m. Because the existing dynamic models struggled to replicate field performance, the model created in this study had limited predictive capabilities. The four levels of fluvial heterogeneities of megascopic, mesoscopic, macroscopic, and microscopic scales were used to better understand the heterogeneities of these minor reservoirs. This has helped to compartmentalize the reservoir based on interpretation of the dynamic data without compromising geological understanding.

RESERVOIR CHARACTERIZATION OF THE ‘SHULA FIELD’, OFFSHORE NIGER DELTA BASIN, NIGERIA: AN INTEGRATED APPROACH

This study analyzed “Shula field” offshore Niger Delta basin for it hydrocarbon bearing capacity. Well logs and seismic data were used for the analysis. Well logs consisting of gamma ray, resistivity, neutron and density logs for five different wells were used. Gamma ray logs aided lithological identification, resistivity logs were used to delineate hydrocarbon bearing zones while a combination of neutron and density logs aided in distinguishing oil and gas zones. Three hydrocarbon bearing sands (reservoirs) of varying thickness designated as RES-AA, RES-BB and RES-CC were identified. Well log correlation of the five wells revealed lateral continuity of the sand units thinning out in northwestern direction of the study field. The range values of gross thickness (GT), net-to-gross (NTG), volume of shale (VSH), effective porosity (ΦEff), permeability (K), hydrocarbon saturation (Sh) and water saturation (SW) for RES-AA reservoir are 51-74ft, 0.88-98%, 0.10-11%, 24-28%, 174-734mD, 8-80%, and 20-92% respectively. RES-BB reservoir range values of (GT), (NTG), (VSH), (ΦEff), (K), (Sh) and (SW) are 47-65ft, 83-98%, 8-14%, 24-32%, 234-1880mD, 4-78%, and 22-96% respectively while the RES-CC reservoir range values of (GT), (NTG), (VSH), (ΦEff), (K), (Sh) and (SW) are 121-191ft, 82-96%, 8-11%, 23-31%, 125-1352mD, 9-88% and 12-91% respectively. Sixteen faults were identified and interpreted comprising of nine synthetic and seven antithetic faults. The time and depth structural maps show the subsurface structural geometry and possible hydrocarbon migration and trapping potential. The probable structure trapping hydrocarbon in the study field is anticlinal structure and four-way closure. The volumetric calculation revealed that reservoir RES-AA has 951 × 106 bbl, reservoir RES-BB has 1058 × 106 bbl and reservoir RES-CC has 1688 × 106 bbl of oil originally in place (OIIP). Generally, the petrophysical results and the volumetric calculation for the field confirm an economically viable investment potential except for reservoir RES-AA, wellbore ZY-005 with 8% Sh, reservoir RES-BB, wellbore ZY-003 and ZY-005 with 4% Sh, and 7% Sh respectively and reservoir RES-CC, wellbore ZY-005 with 9% Sh. Therefore, these four reservoir units may be screen out during production to reduce the rate of water cut thereby increasing the producing life of the field.

Integrated Modelling and Reservoir Characterization of Ataga Field, Niger Delta Basin, Nigeria

Integrated modelling, well correlation and petrophysical analysis were performed to characterize the reservoirs for optimum hydrocarbon correlation using 3-D seismic reflection data and suites of well logs from Ataga 5, 7, 10 and 11 wells respectively in Ataga field, shallow offshore, Niger Delta Basin, Nigeria. The study revealed the presence of two viable hydrocarbon bearing reservoirs, AT1 and AT2 and the average values of porosity, permeability, water saturation, hydrocarbon saturation, Net to Gross (NTG) and volume of shale are in the ranges of 15% - 77%, 44.5% - 75.5%, 25.5% - 85%, 15% - 75.5%, 0.70 - 0.88 and 0.11 - 0.38 respectively which goes further to show that the both reservoirs have fair characteristics that are suggestive of the presence of hydrocarbon accumulation. It can therefore be deduced that the permeability values are reflective of fair interconnectivity of pore spaces of sands within the well areas and their ability to transmit fluids, the depth and depth structural map generated for the horizons and structures shows that the most dominant trapping mechanism in the area under study is the crescentic growth fault and the rollover anticlines trending in the Northwest-Southeast direction and from the volumetric analysis. It can be deduced that the recoverable gas for AT1 and AT2 reservoirs is 2 × 106 mscf and 6 × 106 mscf respectively.

Petrophysical Evaluation of H-field, Niger Delta Basin for Petroleum Plays and Prospects

Abstract in English As a result of a combination of several methodologies, the H-Field, Niger-Delta, has been delineated. To identify probable reservoirs, seals, and source rocks in the study area, this study integrates sequence stratigraphy with petrophysical concepts through a comprehensive analysis of 3D seismic and well logging datasets. According to the 3D facies model, reservoirs are dominated by sand and are laterally extensive. They were then upscaled and stochastically distributed to create a 3D reservoir property model. On average, the porosity of these clastic reservoirs ranges from 22 to 28%. Reservoir net-to-gross (NTG) ratios range from 0.67 to 0.96. Water saturation ranges from 8% to 30%, while hydrocarbon saturation ranges from 70% to 92%. Four gas-bearing units and six oil-bearing units are present in reservoirs P 0.5 and P 1 compartments. All reservoir intervals’ oil and gas volumes are evaluated based on the hydrocarbon distribution. Geological models of the subsurface, such as the one in this paper, are crucial for future reservoir development programs.

Reservoir characterization using integrated seismic attributes and petrophysical parameters in an onshore field of Niger delta basin

An integrated approach of reservoir characterization of a field was performed using seismic attributes and petrophysical parameters for the evaluation of subsurface geological features and hydrocarbon potential of an onshore field in Niger Delta Basin. Four reservoir intervals were identified within the field wells based on their position within the stratigraphic column, and the reservoir correlation, which was aided using the principle of uniform horizontality, based on the simple rule that sediments are deposited horizontally and basic understanding of sequence stratigraphy. The study revealed that, the four reservoirs were predominantly sand units intercalated with shale within the reservoir units. The petrophysical evaluation revealed the Net to Gross (NTG) values ranges from 79% to 87% within the reservoir units, while the effective porosity ranges from 17% to 21%, the permeability ranges between 1307mD to 1678mD across the reservoir units, while the water saturation ranges from the lowest of 35% (Reservoir C) to 78% in reservoir D. A total of fifteen faults were interpreted using the seismic data, while the surface maps (Time and depth surface maps) revealed the identified closures which are anticlinal structures that are fault dependent. The characterization of the reservoir was further enhanced using the seismic attributes (structural and stratigraphic) extracted such as Reflection intensity, Sweetness, Variance, Envelope, Instantaneous frequency, Time gain, Trace AGC, Local structural dip, Gradient magnitude and RMS amplitude. The results shows moderate to high sweetness (sweet spots) within the zone of interest, while the Envelope attribute show acoustic impedance contrasts indicating discontinuities, lithology changes and possible present of hydrocarbon (Bright spots). The variances and gradient magnitude enhanced the signal to map out discontinuities caused by faults and fractures which are signature that enabled delineation of the zone. The integrated approach validates the lithology discrimination of the elastic properties from the well logs and its effectiveness in optimizing and proper understanding of the subsurface, thus identifying and unmasking hidden features within the reservoir (probable bypass) in the field. The study has revealed that the integration of seismic attributes with petrophysical parameters is a better characterization method for fluid and lithology discrimination of a field in any given reservoir study.

Quantitative Interpretation of Petrophysical Parameters for Reservoir Characterization in an Onshore Field of Niger Delta Basin

Reservoir characterization of a field was performed using petrophysical parameters for the evaluation of subsurface geological features and hydrocarbon potential of an onshore field in Niger Delta Basin. Four reservoir intervals were identified within the field wells based on their position within the stratigraphic column, and the reservoir correlation, which was aided using the principle of uniform horizontality, based on the simple rule that sediments are deposited horizontally and basic understanding of sequence stratigraphy. The study revealed that, the four reservoirs were predominantly sand units intercalated with shale within the reservoir units. The petrophysical evaluation revealed the Net to Gross (NTG) values ranges from 79% to 87% within the reservoir units, while the effective porosity ranges from 17% to 21%, the permeability ranges between 1307mD to 1678mD across the reservoir units, while the water saturation ranges from the lowest of 35% (reservoir C) to 78% in reservoir D. The approach validates the lithology discrimination of the elastic properties from the well logs and its effectiveness in optimizing and proper understanding of the subsurface, thus identifying and unmasking hidden features within the reservoir (probable bypass) in the field. The study has revealed that petrophysical parameters can be used quantitatively to characterize a field in terms of its lithology and fluid contents of the reservoir.

A simulation study of in-situ NAPL remediation treatment by using surfactant and foam processes in a military base South Korea

Surfactant and foam processes have been widely used to enhance oil recovery from petroleum-bearing geological formations, and also been recently extended to remediate non-aqueous-phase-liquid (NAPL) contaminants from the shallow subsurface. This study investigates the potential of using surfactant and foam processes for the in-situ remediation treatments within a military base in South Korea: first, optimizing the subsurface permeability and net-to-gross (NTG) values based on history matching and machine-learning algorithm; second, performing simulations that successfully predict the surfactant/foam processes applied in the field; and third, expanding simulations that evaluate different scenarios that might have been used for field tests.The site for the pilot-scale testing, located in the existing fuel-distribution facilities within a military base, has 5 m × 5 m treatment area with 3 m depth, prepared with 3 injection wells and 3 extraction wells. The NAPL of interest is a mixture of various oil compounds showing the average oil saturation of 5%. The overall remediation process applied consists of two major steps: the first is a 20-day injection of surfactant solution (Tween 80) to mobilize the oleic phase trapped by capillary force, and the second is a 3-day injection of foam (i.e., gas and surfactant co-injection) to control the mobility of injected gas and overcome the heterogeneity of the underground system.The major findings of this study are (i) surfactant/foam processes can be an effective means of NAPL recovery from shallow subsurface recovering more than 90% of contaminants, and (ii) computer simulations can be a useful tool for evaluating the in-situ treatment and improving the design of similar operations.

Quantitative Analysis of the Main Controlling Factors of Oil Saturation Variation

With the high-speed development of artificial intelligence, machine learning methods have become key technologies for intelligent exploration, development, and production in oil and gas fields. This article presents a workflow analysing the main controlling factors of oil saturation variation utilizing machine learning algorithms based on static and dynamic data from actual reservoirs. The dataset in this study generated from 468 wells includes thickness, permeability, porosity, net-to-gross (NTG) ratio, oil production variation (OPV), water production variation (WPV), water cut variation (WCV), neighbouring liquid production variation (NLPV), neighbouring water injection variation (NWIV), and oil saturation variation (OSV). A data processing workflow has been implemented to replace outliers and to increase model accuracy. A total of 10 machine learning algorithms are tested and compared in the dataset. Random forest (RF) and gradient boosting (GBT) are optimal and selected to conduct quantitative analysis of the main controlling factors. Analysis results show that NWIV is the variable with the highest degree of impact on OSV; impact factor is 0.276. Optimization measures are proposed for the development of this kind of sandstone reservoir based on main controlling factor analysis. This study proposes a reference case for oil saturation quantitative analysis based on machine learning methods that will help reservoir engineers make better decision.

A New Insight of Talang Akar Formation in the Ridho Field, North Palembang Sub-basin, Indonesia: An Integrated Approach

The synrift sandstone deposits of Eo-Oligocene Lemat (LMF) and Oligo-Miocene Talang Akar Formations (TAF) are the most well -known hydrocarbon reservoirs in the South Sumatra Basin, Indonesia. However, only limited studies on TAF in the North Palembang Sub-Basin have been published. In the Ridho field, TAF is characterized by fining-up sequences of inter bedded, fine to medium-grained sandstones and shales overlain by a coal layer as the top marker, while LMF comprises of continuous blocky-shaped, medium to coarse-grained, conglomeratic sandstones.Previous lithostratigraphy-driven sand to sand correlation between wells has created difficulties in understanding the geology and in producing consistent correlation, especially within the TAF. In order to define chronostratigraphy-based correlation and interpret the depositional environment of TAF and LMF, an integration between palynological, core study and petrophysical analysis was performed. The result of this integrated approach demonstrates aligned hypotheses. The occurrence of pollen Meyeripollis naharkotensis and Florschuetzia trilobata along the studied wells suggest Late Oligocene age. The palynology study subdivides TAF into three backmangrove-intertidal sand units with an increase of marine influence defining a transgression to the top of the TAF. The transgressive event is identified in core sample by lesser tidal influx sedimentary structures such as ripple, mudlayer, flaser and also finer grained sandstone at the top of TAF. Furthermore, based on petrophysical evaluation, better sand quality with lower NTG (net -to gross) near top TAF confirms the retrogradational event in this formation.The new sand unit definitions from the current study provide more consistent correlation in terms of sand thickness and characteristics for future modeling purposes.

Understanding reservoir heterogeneity using variography and data analysis: an example from coastal swamp deposits, Niger Delta Basin (Nigeria)

Abstract For efficient reservoir management and long-term field development strategies, most geologists and asset managers pay special attention to reservoir chance of success. To minimise this uncertainty, a good understanding of reservoir presence and adequacy is required for better ranking of infill opportunities and optimal well placement. This can be quite challenging due to insufficient data and complexities that are typically associated with areas with compounded tectonostratigraphic framework. For the present paper, data analysis and variography were used firstly to examine possible geological factors that determine directions in which reservoirs show minimum heterogeneity for both discrete and continuous properties; secondly, to determine the maximum range and degree of variability of key reservoir petro-physical properties from the variogram, and thirdly, to highlight possible geological controls on reservoir distribution trends as well as areas with optimal reservoir quality. Discrete properties evaluated were lithology and genetic units, while continuous properties examined were porosity and net-to-gross (NtG). From the variogram analysis, the sandy lithology shows minimum heterogeneity in east-west (E–W) and north-south (N–S) directions, for Upper Shoreface Sands (USF) and Fluvial/Tidal Channel Sands (FCX/TCS), respectively. Porosity and NtG both show the least heterogeneity in the E–W axis for reservoirs belonging to both Upper Shoreface and Fluvial Channel environments with porosity showing a slightly higher range than NtG. The vertical ranges for both continuous properties did not show a clear trend. The Sequential Indicator Simulation (SIS) and Object modelling algorithm were used for modelling the discrete properties, while Sequential Gaussian Simulation (SGS) was used for modelling of the continuous properties. Results from this exercise show that depositional environment, sediment provenance, topographical slope, sub-regional structural trends, shoreline orientation and longshore currents, could have significant impacts on reservoir spatial distribution and property trends. This understanding could be applied in reservoir prediction and for generating stochastic estimates of petrophysical properties for nearby exploration assets of similar depositional environments.

Systematic Approach to Well Productivity Evaluation To Determine the Significance of Formation Damage for Wells Drilled in a Depleted Reservoir without Bridging Particles: Oseberg Main Case History

Summary As part of an Equinor technical efficiency program that was initiated in 2015 to deliver savings and improvements, bridging particles were removed from the drilling fluids of 15 wells in Oseberg Main and instead loss control material (LCM) was used, as required, in some but not all the wells. These long, horizontal wells were a combination of open hole (OH) and sand screens with and without inflow control together with cased and perforated (C&P) completions, producing from typical Brent Group sandstone formations with permeabilities varying from approximately 10 md to darcy sandstones, and which were depleted by as much as approximately 280 bars. In 2018, an extensive study was performed on these wells to determine the impact on inflow performance of drilling without bridging particles. It was realized that the 15 wells offered a worst-case scenario to study in the field rather than laboratory the significance of formation damage on well productivity. The data set generated offered a unique opportunity to challenge conventional formation damage assertions, especially for long, horizontal wells. The influence of different parameters, including LCMs, lower completion design, loss type, mud penetration depth, dynamic overbalance while drilling, length of production interval, net to gross (NTG) and kh were considered for those wells drilled without bridging particles. One of the surprising findings was that there was no clear evidence that losses were detrimental to the productivity of these long horizontal wells; i.e., it would appear that the Brent reservoir sections, despite being depleted, were more resistant to the influence of formation damage on inflow performance than first thought. Furthermore, for this example bridging particles appear to be of less importance in the avoidance of formation damage but are important in preventing excessive increases in fluid costs due to losses. After a thorough review of all the data obtained from this study, together with the conclusions drawn, it was realized that these had direct implications for Equinor's approach to fluid qualification, and especially coreflooding. The most important conclusion that influenced this change in approach was that the long reservoir sections (approximately 1 km or more) within typical Brent heterogeneous formations appear to tolerate more formation damage without impairing the productivity index (PI). A direct consequence of this was the conclusion that more emphasis should be placed on fluid compatibility, mobility, screen plugging and stability along with particle-size distribution (PSD) design, while the importance of coreflooding to fluid qualification was downgraded for Brent and reservoirs of similar characteristics. This is not to say that coreflooding will not be performed, but rather it will be targeted toward situations where the influence of formation damage on well productivity is more significant; e.g., high-pressure and high-temperature fields where special drilling and completion fluids are required, low-permeability formations without mechanical stimulation, and shallow reservoirs with low reservoir temperature. In this paper, we will perform an evaluation of the significance of formation damage on well productivity and use this to demonstrate Equinor's revised approach to formation damage laboratory evaluation based on field experiences.

3-D static modelling of lateral heterogeneity using geostatistics and artificial neural network in reservoir characterisation of “P” field, Niger Delta

ABSTRACT The anisotropic and heterogeneous nature of the subsurface units at offset wells gets more complex at locations outside well control. However, qualitative and quantitative predictions of reservoir properties and geometries beyond well control are vital to understanding the intrinsic characteristics of subsurface formations. Supervised Multi-layer Perceptron neural network and conditional sequential Gaussian simulation were applied to a suite of well logs data set and three dimensional (3-D) seismic dataset acquired from P-field, Niger Delta to predict lateral continuity of hydrocarbon reservoir properties. Multilayer perceptron neural network was used to model effective porosity (Eϕ) at the root-mean-square error of 0.00531 with an estimated average effective porosity of 0.2952. Furthermore, MLPNN modelling of hydrocarbon saturation (Sh) at root mean square error of 0.02821 yielded an estimated average of 69.73%. The volume of shale (Vsh) was also modelled at the root mean square error of 0.0282, with an estimated Vsh average of 9% for the study area. It was discovered that a comparatively higher net-to-gross (N-T-G), relatively higher effective porosity, high hydrocarbon saturation, very low volume of shale, and high permeability were observed in the areas of interest in the study area. A geostatistical approach was also used to model petrophysical properties. The parametric semivariogram model shows the range of 94–5230 m, nugget effect of 0.062, and sills of 0.075, 0.093, and 0.0121. Realisations were generated and ranked using the SGS algorithm suggest that any one of the realisations can independently represent the real picture of the subsurface geology within the study area. The integration of these different prediction tools and analyses of the outcomes from the research has improved our understanding of delineated reservoirs and improved lateral variation prediction of its properties. These prediction tools served better as a complementary tool to each other rather than as a comparison tool.

Static connectivity of stacked deep-water channel elements constrained by high-resolution digital outcrop models

High-resolution digital outcrop models of stacked deep-water channel elements are constructed from the Laguna Figueroa section of the well-exposed Upper Cretaceous Tres Pasos Formation in Chilean Patagonia. The models are based on greater than 1600 m (>5250 ft) of centimeter-scale measured sections, greater than 100 paleoflow measurements, and thousands of differential global positioning system points (10-cm [4-in.] accuracy) from an outcrop belt that is approximately 2.5 km (∼1.5 mi) long and 130 m (425 ft) thick. The models elucidate the effects bed-to-geobody–scale architecture has on static sandstone connectivity among a series of stacked deep-water channel elements and how that connectivity is altered by grid cell size. Static connectivity analyses show that channel element base drapes can strongly influence sandstone connectivity and that smaller channel element widths are more likely to produce disconnected sandstone geobodies. Net-to-gross (NTG) is not directly correlated with connectivity because of the presence of thin channel element base drapes, which do not significantly contribute to NTG. Upscaling the models consistently increases channel element contact (up to 10%) but decreases sandstone connectivity (up to 2%–3%). Channel element stacking patterns strongly impact connectivity. For example, connectivity is reduced in cases of high lateral channel element offsets. Increasing drape coverage markedly decreases connectivity. Evaluating connectivity in a vertical, along-system profile is critical to understanding flow units and reservoir piping. Ultimately, this work constrains uncertainty related to the impact of subseismic-scale stratigraphic architecture on reservoir connectivity by providing concrete knowledge that can be used to guide the model building process.

Discrete-NTG Truncated Gaussian Simulation: An Alternative Modeling Approach for Coal-Seam-Gas Unconventional Reservoirs, Bowen Basin, Eastern Australia

Summary Building a representative static model for predicting and monitoring the performance of coal-seam gas (CSG) fields presents several complex and unique challenges. The individual reservoirs possess different coal architectures, often with highly complex seam splitting, amalgamating, and structural deformation. Our objective was to develop an alternative approach that honored log and core data capturing both the lateral heterogeneity and the vertical signature of the Bowen Basin coals in Central Queensland. In some areas of the Bowen Basin, coals can be thick and laterally continuous; picking the top and base of each seam works well in small models with homogeneous coals. As seam geometries begin to increase in complexity and coals become more heterogeneous in nature with thinner seams in multiple packages, then a net-to-gross (NTG) approach is often more appropriate. Each method has its merits. The former approach describes the reservoir architecture but implies a certain degree of confidence in coal correlation. In a vast field with complex seam splitting and merging with abundant drilling data, it might not be a practical technique. The NTG method disregards coal-seam architecture and reservoir connectivity. The proposed workflow is a hybrid approach using discrete modeling algorithms and data-analysis tools on continuous NTG properties. The process operates on a relatively coarse chronostratigraphic framework in which coal is captured as contiguous discrete-NTG “facies.” The use of the truncated Gaussian model ensures the ordering of NTG facies and mimics transitions between coals and the surrounding interburdens. With the adoption of facies vertical proportion trends, we are able to replicate a similar coal-seam signature laterally away from the wellbore. The definition of a categorical coal model allows the proper scaling of seams with different coal-quality characteristics. With the successful geocellular-model construction and history match of two historical CSG fields in the Bowen Basin, the discrete-NTG truncated Gaussian simulation (TGS) approach has proved to be a valid alternative CSG-modeling technique.

A novel method to improve water saturation in shaly sand reservoirs using wireline logs

Water saturation in shaly reservoirs is a difficult task due to the heterogeneity nature of shale and the way the shale distributed in the reservoirs. So, many scientists proposed several models for water saturation in shaly sandstone reservoirs. So far, the most reliable techniques depend on identification of shale habitat qualitatively to apply suitable water saturation model, these techniques can lead to inaccurate identification of shale habitat, especially when dealing with a mixture of different shale modes and massive superimpose well logging data, and hence drastically erroneous values of water saturation and hydrocarbon reserves. Well logs and routine core analysis from two main fields in Egypt. The North Sinai and the Gulf of Suez fields are used for this study to evaluate the novel proposed method. Unlike other qualitative methods, a new robust method has been introduced to determine accurate volumes of shale distribution types. This volumetric method checked for validation and accuracy using Thomas-Stieber crossplot, the results show good and a reliable degree of accuracy. Consequently, appropriate water saturation models can apply accurately. While the dispersed shale model is adequate to estimate water saturation in dispersed shale reservoirs, water saturations for laminated shaly sand reservoirs are more complicated. So, a new approach and algorithms have been introduced to evaluate water saturation in these complex problematic reservoirs specifically in the absence of triaxial induction resistivity measurements. Furthermore, to prove the superiority of this novel method over traditional techniques, a comparative study and statistical analysis performed between the new water saturation method and conventional techniques by using InetillLog software © 2015. These comparisons and statistics show a remarkable discrepancy and variance in values between conventional methods and the new method, where water saturation values obtained from conventional methods for two fields are drastically lower than the new method. This can lead to erroneous water saturation and hydrocarbon estimations. Water saturations derived from the new method were in perfect agreement with the corresponding water saturations from cores data. Moreover, scatter diagrams between water saturation from novel method and that from core analysis obtained correlation coefficient (R2) values of 0.82, 0.85, for the North Sinai and the Gulf of Suez fields, respectively, indicating strong linear relationships. Furthermore, this new method is taken care of one of several pitfalls of LSSA interpretation method. So, this novel method adds a valuable improvement in water saturation, the assessment of hydrocarbon saturation in shaly reservoirs, continuous Net To Gross (NTG) calculations, net pay detection, reservoir simulation, and reserve estimation.