scholarly journals Analyzing and evaluation of vintage logs for an integrated reservoir characterization and field development strategy

2020 ◽  
Author(s):  
Abdulmalik Taj-Liad
Keyword(s):  
Development Strategy ◽  
Reservoir Characterization ◽  
Gamma Ray ◽  
Water Saturation ◽  
Computing Time ◽  
Development Study ◽  
Field Development ◽  
The North ◽  
Python Scripting ◽  
East West

Obom field is a mature field in the Greater Ughelli onshore Niger delta, which has been producing since 1967. The field is a simple rollover structure elongated in the east-west direction, and bounded to the north by an east-west trending, south-hading, main growth fault. The reservoirs are made mainly of channel/shoreface complexes. The closures are faults assisted dip closures in shallow reservoir and dip assisted fault closure in deeper sections. As a huge producing field with some potential for further sustainable production, field monitoring is therefore important in the identification of areas of unproduced hydrocarbon. The aim of this study is to evaluate and train logs which will be an input into other discipline for an integrated field development study. Petrophysical parameters were evaluated from logs and plots of shaly sand saturation equations (Waxman smith and Normalized Qv method) were compared to water saturation from drainage capillary pressure and a good match was observed. Due to some radioactive reservoir levels without density and neutron logs, volume of shale was evaluated from both gamma ray (GR) and spontaneous potential (SP) log which was later spliced with data editor to give a final volume of shale . Furthermore, paucity of density logs drove the decision to use neural network for density log training from SP logs- using density SP logs would capture the radioactive level - and TVDSS which went into Seismic to well tie for horizon interpretation. With the aid of python scripting, the flow zone indicator (FZI) workflow was used in evaluating the permeability and hydrocarbon correction on porosity was also done. The use of python scripting saved computing time by more than 70% due to the numbers of wells in the field - fourteen wells. This study demonstrates the effectiveness of integrating trained dataset for a field development study. Hence, has provided a framework for future prediction of reservoir performance and production behavior of the field.

scholarly journals Characterization of Mishrif Formation Reservoir in Amara Oil Field, Southeast Iraq, Using Geophysical Well-logging

2021 ◽  
pp. 4702-4711
Author(s):  
Asmaa Talal Fadel ◽  
Madhat E. Nasser
Keyword(s):  
Reservoir Characterization ◽  
Gamma Ray ◽  
Water Saturation ◽  
Total Porosity ◽  
Effective Porosity ◽  
Oil Field ◽  
Neutron Density ◽  
Reservoir Water ◽  
Resistivity Logs ◽  
Reliable Knowledge

     Reservoir characterization requires reliable knowledge of certain fundamental properties of the reservoir. These properties can be defined or at least inferred by log measurements, including porosity, resistivity, volume of shale, lithology, water saturation, and permeability of oil or gas. The current research is an estimate of the reservoir characteristics of Mishrif Formation in Amara Oil Field, particularly well AM-1, in south eastern Iraq. Mishrif Formation (Cenomanin-Early Touronin) is considered as the prime reservoir in Amara Oil Field. The Formation is divided into three reservoir units (MA, MB, MC). The unit MB is divided into two secondary units (MB1, MB2) while the unit MC is also divided into two secondary units (MC1, MC2). Using Geoframe software, the available well log images (sonic, density, neutron, gamma ray, spontaneous potential, and resistivity logs) were digitized and updated. Petrophysical properties, such as porosity, saturation of water, saturation of hydrocarbon, etc. were calculated and explained. The total porosity was measured using the density and neutron log, and then corrected to measure the effective porosity by the volume content of clay. Neutron -density cross-plot showed that Mishrif Formation lithology consists predominantly of limestone. The reservoir water resistivity (Rw) values of the Formation were calculated using Pickett-Plot method.   

Validation of flow capacity and state-of-stress models in unconventional reservoirs by implementation of numerical models of diagnostic fracture injection tests

2019 ◽  
Vol 38 (6) ◽  
pp. 465-472
Author(s):  
Hernán Buijs ◽  
Jorge Ponce ◽  
Paul Veeken
Keyword(s):  
Development Strategy ◽  
Hydraulic Fracture ◽  
Reservoir Characterization ◽  
Numerical Models ◽  
Solution Space ◽  
Production Performance ◽  
Fracture Geometry ◽  
Field Development ◽  
Flow Capacity ◽  
Planar Shear

Diagnostic fracture injection tests contain critical information for reservoir characterization and hydraulic fracturing design, defining every input and output of the simulation modeling process. They help to assess the expected fracture geometry, proppant pack conductivity, formation flow capacity, and optimum hydraulic fracture design. At the same time, these data provide the necessary means to place a frac job adequately. However, interpretation challenges and inherent modeling nonuniqueness demonstrate the need for more constraints to reduce the solution space. Proprietary workflows have been applied using a 3D planar shear decoupled hydraulic fracture simulator to several vertical wells in the Vaca Muerta play in Argentina. The generated information makes it possible to build models consistent with multiple independent measurements from bottom-hole gauges, near wellbore, and far-field assessments of fracture geometry, which permit us to better understand production performance of the wells. The proposed workflow can be utilized to collapse the learning curve in a significant and meaningful way, playing a vital role in the optimization of horizontal wells and the field development strategy.

scholarly journals Re-evaluation of Petro physical Properties in Yammama Formation at Nasiriya Field

2019 ◽  
Vol 20 (3) ◽  
pp. 59-66
Author(s):  
Karrar Hayder Jassim ◽  
Jalal A. Al-Sudani
Keyword(s):  
Physical Properties ◽  
Gamma Ray ◽  
Water Saturation ◽  
Uranium Content ◽  
Geological Model ◽  
North West ◽  
Shale Volume ◽  
The North ◽  
Volume Porosity ◽  
Gamma Ray Log

Nasiriya field is located about 38 Km to the north – west of Nasiriya city. Yammama, a giant lower cretaceous reservoir in Nasiriya field which is lithologically formed from limestone. Yammama mainly was divided into three main reservoir units YA, YB1, YB2 and YB3 and it is separated by impermeable layers of variable thickness. An accurate petro physical evolution of the reservoir is of great importance perform an excellent geological model so that four petro physical properties which are shale volume, porosity, water saturation and permeability was re-evaluated. The volume of shale was calculated using the density and neutron logs (VSH-DN) rather than using gamma ray log because of presence a uranium content in the formation that makes overestimation of shale volume. Cross plots of Density Neutron logs are used to determine porosity by using IP software, which is correcting automatically Density Neutron logs for the effect of shale. Indonesian equation was used to estimate water saturation for five wells rather than Archie equation in order to consider shale volume. Fuzzy logic was adopted to predict permeability instead of regression analysis (cross plot) because of presence of errors in the results in this method. The results are shown that units YB2 and YB3 have best reservoir quality.

The Importance of Identifying the Evidence of Hydrodynamic Trapping for New Well Placement in Mature Offshore Stupa Field

2020 ◽  
Author(s):  
A. Anshariy
Keyword(s):  
Development Strategy ◽  
Target Location ◽  
Well Placement ◽  
Field Development ◽  
Contact Mapping ◽  
Trapping Mechanism ◽  
The North ◽  
Gas Potential ◽  
Pseudo Potential ◽  
Hydrodynamic Trapping

To predict the hydrocarbon limit and new well placement for future development in the mature Stupa field, hydrodynamic trapping analysis is carried out to find a solution of “tilted” contact hypothesis. The static and dynamic data of 6 exploration wells and 12 development wells were used to recognize the evidence of hydrodynamic trapping. There are multiple pieces of such evidence for hydrodynamic trapping such as variation in fluid contacts, lateral reservoirs drainage and variation of water pseudo potential. This paper will describe identification of tilted gas – water contacts related to hydrodynamic trapping mechanism plays, to predict and map the tilted contact using “u” map as a limit of the field and how a tilted gas-water contacts map leads for opportunity to identify future well development. It is concluded that the hydrodynamic trapping is working in the Stupa field. A new limit of hydrocarbon accumulation as a result of tilted contact mapping using “U” map has significantly changed the field development strategy in the Stupa field. The West Stupa Panel has now become the new target location of future field development for prolonging the production life of the mature Stupa field. At the end of 2019, one development well was drilled at the north flank of West Stupa Panel and showed very good results, which unlocked the remaining gas potential of this panel. Following this positive result, 3 other wells are proposed to develop the remaining stakes in this panel. Identifying the evidence of hydrodynamic trapping and mapping the tilted gas – water contacts had opened new opportunities for further field development in flank areas of the mature gas Stupa field.

Oil and Gas Reservoir Characterization; A Case Study of Agbada Field

GIS Business ◽  
2019 ◽  
Vol 14 (5) ◽  
pp. 54-63
Author(s):  
Elenwo Nador ◽  
Fidelis O. Wopara ◽  
Ehirim O. . Emmanuel
Keyword(s):  
Structural Characterization ◽  
Oil And Gas ◽  
Reservoir Characterization ◽  
Water Saturation ◽  
Volume Estimation ◽  
Neutron Density ◽  
Structural Element ◽  
Water Contact ◽  
The North ◽  
Net To Gross

This study on reservoir characterization was conducted using seismic data and well logs. The aim was to characterize the petrophysical properties and structural element in the field for hydrocarbon volume estimation and determination of infill well locations. Three reservoirs were identified (J100, K100, L100) at shallow, middle and deep depths and correlated across the field using gamma ray log. Petrophysical characterization revealed porosity ranges from 25 to 27% in J100 reservoir, 16% to 27% in K100 reservoir and 11 and 18% in L100 reservoir. This shows good to very good porosity values for reservoir rocks. On average, water saturation is 80%, 68% and 70% in J100, K100, and L100 reservoirs. Net to gross ranged from 24 to 77% in J100, 38 to 82% in K100 and 29 to 75% in L100 and L100 reservoir. Average net to gross revealed that the sands are cleaner with depth. Resistivity and neutron-density logs revealed the reservoirs are oil bearing. Structural characterization of seismic date revealed the presence of synthetic and antithetic faults. Depth structure maps generated revealed closures that are anticlinal and fault supported. Oil water contact super-imposed on the structural maps revealed closures that were oil bearing. Estimation of stock tank oil initially in place revealed 19.511 mmstb, 73.576 mmstb and 19.169 mmstb for J100, K100 and L100 reservoirs respectively, indicate that they can be produced at significant profits. Two infill well placement locations were identified from petrophysical and structural characterization; one at the north central part of J100 reservoir and another at the North-Western part of K100 reservoir.

scholarly journals A field development strategy for the joint optimization of flow allocations, well placements and well trajectories

2020 ◽  
pp. 014459872097442
Author(s):  
M A Dada ◽  
M Mellal ◽  
A Makhloufi ◽  
H Belhouchet
Keyword(s):  
Genetic Algorithm ◽  
Development Strategy ◽  
Oil And Gas ◽  
Water Saturation ◽  
Optimization Methods ◽  
Optimization Techniques ◽  
Production Optimization ◽  
Well Placement ◽  
Field Development ◽  
Maximum Duration

One of the major goals that field planning engineers and decision makers have to achieve in terms of reservoir management and hydrocarbon recovery optimization is the maximization of return on financial investments. This task yet very challenging due to high number of decision variables and some uncertainties, pushes the engineers and technical advisors to seek for robust optimization methods in order to optimally place wells in the most profitable locations with a focus on increasing the net-present value over a project life-cycle. The quest to deliver a good quality advice is also dependent on how some uncertainties – geologic, economic and flow patterns – have been handled and formulated all along the optimization process. With the enhancement of computer power and the advent of remarkable optimization techniques, the oil and gas industry has at hand a wide range of tools to get an overview on value maximization from petroleum assets. Amongst these tools, genetic algorithms which belong to stochastic optimization methods have become well known in the industry as one the best alternatives to apply when trying to solve well placement and production allocation problems, though computationally demanding. The aim of this work is to present a novel approach in the area of hydrocarbon production optimization where control settings and well placement are to be determined based on a single objective function, in addition to the optimization of wells’ trajectories. Starting from a reservoir dynamic model of a synthetic offshore oil field assisted by water injection, the work consisted in building a data-driven model that was generated using artificial neural networks. Then, we used Matlab’s genetic algorithm toolbox to perform all the needed optimizations; from which, we were able to establish a drilling schedule for the set of wells to be realized, and we made it possible to simultaneously get the well location and configuration (vertical or horizontal), well type (producer or injector), well length, well orientation – in the horizontal plane –, as well as well controls (flow rates) and near wellbore pressure with respect to a set of linear and nonlinear-constraints. These constraints were formulated so as to reproduce real field development considerations, and with the aid of a genetic algorithm procedure written upon Matlab, we were able to satisfy those constraints such as, maximum production and injection rates, optimal wellbore pressures, maximum allowable liquid processing capacity, optimal well locations, wells’ drilling and completion maximum duration, in addition to other considerations. We have investigated some scenarios with the intention of proving the benefits of development strategy that we have chosen to study. It was found the chosen scenario could improve NPV by 3 folds in comparison to a base case scenario. The positioning of the wells was successful as all producers were placed in zones having initial water saturation less than 0.4., and all injectors were placed high water saturation zones. Moreover, we established a procedure regarding well trajectory design and optimization by taking into account, minimum dogleg severity and maximum duration for a well to be drilled and completed with respect to a time threshold. The findings as well as the workflow that will be presented hereafter could be considered as a guideline for subsequent tasks pertaining to the process of decision making, especially when it has to do with the development of green oil and gas fields and will certainly help in the placement of wells in less risky and cost-effective locations.

scholarly journals Hydrocarbon Reservoir Characterization of ‘Khume’ Field, Offshore Niger Delta, Nigeria

2021 ◽  
pp. 47-60
Author(s):  
K. A. Obakhume ◽  
O. M. Ekeng ◽  
C. Atuanya
Keyword(s):  
Niger Delta ◽  
Reservoir Characterization ◽  
Gamma Ray ◽  
Water Saturation ◽  
Seismic Interpretation ◽  
Effective Porosity ◽  
Well Logs ◽  
Integrative Approach ◽  
Neutron Density ◽  
Hydrocarbon Reservoir

The integrative approach of well log correlation and seismic interpretation was adopted in this study to adequately characterize and evaluate the hydrocarbon potentials of Khume field, offshore Niger Delta, Nigeria. 3-D seismic data and well logs data from ten (10) wells were utilized to delineate the geometry of the reservoirs in Khume field, and as well as to estimate the hydrocarbon reserves. Three hydrocarbon-bearing reservoirs of interest (D-04, D-06, and E-09A) were delineated using an array of gamma-ray logs, resistivity log, and neutron/density log suites. Stratigraphic interpretation of the lithologies in Khume field showed considerable uniform gross thickness across all three sand bodies. Results of petrophysical evaluations conducted on the three reservoirs correlated across the field showed that; shale volume ranged from 7-14%, total and effective porosity ranged from 19-26% and 17-23% respectively, NTG from 42 to 100%, water saturation from 40%-100% and permeability from 1265-2102 mD. Seismic interpretation established the presence of both synthetic and antithetic faults. A total of six synthetic and four antithetic faults were interpreted from the study area. Horizons interpretation was done both in the strike and dip directions. Time and depth structure maps revealed reservoir closures to be anticlinal and fault supported in the field. Hydrocarbon volumes were calculated using the deterministic (map-based) approach. Stock tank oil initially in place (STOIIP) for the proven oil column estimated for the D-04 reservoir was 11.13 MMSTB, 0.54 MMSTB for D-06, and 2.16 MMSTB for E-09A reservoir. For the possible oil reserves, a STOIIP value of 7.28 MMSTB was estimated for D-06 and 6.30 MMSTB for E-09A reservoir, while a hydrocarbon initially in place (HIIP) of 4.13 MMSTB of oil equivalents was derived for the undefined fluid (oil/gas) in D-06 reservoir. A proven gas reserve of 1.07 MMSCF was derived for the D-06 reservoir. This study demonstrated the effectiveness of 3-D seismic and well logs data in delineating reservoir structural architecture and in estimating hydrocarbon volumes

scholarly journals Stoneley Wave Predicted Permeability and Electrofacies Correlation in the Bangestan Reservoir, Mansouri Oilfield, SW Iran

2018 ◽  
Vol 57 (2) ◽  
Author(s):  
Bahman Soleimani ◽  
Mehrdad Moradi ◽  
Ali Ghabeishavi
Keyword(s):  
Reservoir Characterization ◽  
Gamma Ray ◽  
Water Saturation ◽  
Effective Porosity ◽  
Stoneley Wave ◽  
Stoneley Waves ◽  
Rock Types ◽  
The Matrix ◽  
Sw Iran ◽  
Neutron Porosity

 Reservoir characterization is one of the most important goals for the development of any oilfield. Determination of permeability and rock types are of prime importance to judge reservoir quality. In this research, Stoneley waves from dipole sonic tools were used in order to discover changes in permeability in the Bangestan reservoir, Mansouri oilfield. Index (tortuosity) could be estimated by Stoneley waves. After comparing the permeability resulting from Stoneley waves, cores and the Timur method, it was concluded that all the three permeabilities were very similar. The core porosity and effective porosity from the analysis of well logs were found to match as well. Electrofacies (EF) method, as a clustering method, was utilized to find rock types in order to define reservoir and non-reservoir zones. Simultaneous with EF clustering, gamma ray, neutron porosity, density, sonic, water saturation and porosity (PHIE) data from 78 wells were also considered and interpreted. Nine clusters were defined as a result of the analysis, being reduced to only four clusters after applying PC (capillary pressure) data. Among the four clusters, clusters 1 and 2 contained more vuggy pores than the others. Fracture abundance and solution seams were observed more frequently in EF-3 as compared to other EFs. Based on the matrix type, Archie porosity classification types I and III were recognized. The pore sizes in EFs-1 and 2 were mostly of the B type while in EF-3, it was A type. The EFs generated and determined by Stoneley waves and the well log data were also compared, showing a good correlation.

scholarly journals A Low frequency Southern Sky Survey Using the Mauritius Radio Telescope

2002 ◽  
Vol 199 ◽  
pp. 25-31
Author(s):  
N. Udaya Shankar
Keyword(s):  
Radio Telescope ◽  
Low Frequency ◽  
Fourier Synthesis ◽  
North East ◽  
The North ◽  
Sky Survey ◽  
Correlation Receiver ◽  
Complex Correlation ◽  
Right Ascension ◽  
East West

The Mauritius Radio Telescope (MRT) is a Fourier synthesis instrument which has been built to fill the gap in the availability of deep sky surveys at low radio frequencies in the southern hemisphere. It is situated in the north-east of Mauritius at a southern latitude of 20°.14 and an eastern longitude of 57°.73. The aim of the survey with the MRT is to contribute to the database of southern sky sources in the declination range −70° ≤ δ ≤ −10°, covering the entire 24 hours of right ascension, with a resolution of 4' × 4'.6sec(δ + 20.14°) and a point source sensitivity of 200 mJy (3σ level) at 151.5 MHz.MRT is a T-shaped non-coplanar array consisting of a 2048 m long East-West arm and a 880 m long South arm. In the East-West arm 1024 fixed helices are arranged in 32 groups and in the South arm 16 trolleys, with four helices on each, which move on a rail are used. A 512 channel, 2-bit 3-level complex correlation receiver is used to measure the visibility function. At least 60 days of observing are required for obtaining the visibilities up to the 880 m spacing. The calibrated visibilities are transformed taking care of the non-coplanarity of the array to produce an image of the area of the sky under observation.This paper will describe the telescope, the observations carried out so far, a few interesting aspects of imaging with this non-coplanar array and present results of a low resolution survey (13' × 18') covering roughly 12 hours of right ascension, and also present an image with a resolution of 4' × 4'.6sec(δ + 20.14°) made using the telescope.

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