Baruah, Nabajit (Oil & Natural Gas Corporation) | Mandal, Dipak (Oil & Natural Gas Corporation) | Jena, Smita Swarupa (Oil & Natural Gas Corporation) | Sahu, Sunil Kumar (Oil & Natural Gas Corporation)
This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.
Saluja, Vikas (Oil & Natural Gas Corporation LTD.) | Singh, Uday (Oil & Natural Gas Corporation LTD.) | Ghosh, Aninda (Oil & Natural Gas Corporation LTD.) | Prakash, Puja (Oil & Natural Gas Corporation LTD.) | Kumar, Ravendra (Oil & Natural Gas Corporation LTD.) | Verma, Rajeev (Oil & Natural Gas Corporation LTD.)
The case study demonstrated here is the innovative workflow for fault delineation technique on a 3D seismic volume in B-173A Field of Heera Panna Bassein (HPB) Sector, Western Offshore Basin, India. B-173A is located 50 kms west of Mumbai at an average water depth of about 50 m. The field was discovered in the year 1992 and it was put on production in Aug 1998. In B-173A field there are two hydrocarbon bearing zones one is gas bearing Mukta (Lower Oligocene carbonates) Formation and oil bearing Bassein (Middle to Upper Eocene Carbonates) formation.
The present study is an extended workflow on Advanced Seismic Interpretation using Spectral Decomposition and RGB Blending for Fault delineation. Iso-frequency volumes are extracted from Relative Acoustic Impedance data instead of seismic data itself.
The workflow is for effective fault delineation and it consists of Spectral Decomposition of relative acoustic impedance data and RGB Blending of discontinuity attributes of different Iso-frequency volumes.
It is observed that RGB blend volume of discontinuity attributes provided more convincing results for fault delineation as compared to the results of traditional discontinuity attributes.
Mogollón, J. L. (Halliburton) | Yomdo, S. (OIL India Limited) | Salazar, A. (Halliburton) | Dutta, R. (OIL India Limited) | Bobula, D. (Halliburton) | Dhodapkar, P. K. (OIL India Limited) | Lokandwala, T. (Halliburton) | Chandrasekar, V. (CMG)
The perception of better economics and less risk from infill drilling and recompletions are reasons well-focused remedies are preferred compared to reservoir-focused solutions, such as enhanced oil recovery (EOR). However, most literature does not discuss the economic and risk indicators driving this.
Using a real example, this work demonstrates that combining polymer flooding with infill drilling and recompletion substantially increases economic benefits with reasonable risk.
The reservoir considered is an Oligocene sandstone at a depth of 2700 m. The °API is 29.5 and permeability ranges from 50 to 500 mD. Current reservoir pressure is 43% of the original and it is below bubble point. A black oil model with a 133 × 56 × 128 grid was used. The model incorporated more than 50 years of matched primary and waterflooding production history and experimental polymer physico-chemical parameters. For the stochastic economic risks estimation, 1,000 iterations were run for each scenario considering uncertainties in injection-production, capital expenditures (CAPEX), operational expenditures (OPEX), and oil prices.
For a 20-year horizon, the injection-production-pressure profiles were numerically forecasted; economic results were calculated using a classic model and inputs from the forecast. The economic risk was determined stochastically. The redevelopment scenarios considered were as follows: Base: current waterflooding Existing wells interventions: workover, opening shut-in wells, and new perforations Infill drilling: vertical/horizontal infill drilling wells + existing wells operations Polymer flooding: using existing wells Combined Infill and polymer: vertical infill drilling wells and polymer flooding
Base: current waterflooding
Existing wells interventions: workover, opening shut-in wells, and new perforations
Infill drilling: vertical/horizontal infill drilling wells + existing wells operations
Polymer flooding: using existing wells
Combined Infill and polymer: vertical infill drilling wells and polymer flooding
P50 forecasts showed that interventions in existing wells in the base scenario increased oil production by 11% and net present value (NPV) by 71% with a risk index of 0.38.
A numerical optimizer was used to account for possible combinations of 14 potential drilling locations and vertical to horizontal well ratios. A scenario with three vertical wells was selected. Compared to the base case, this scenario showed an oil production increase of 23%, NPV increase of 178%, and a risk index of 0.41.
The injection rate of the polymer flood was optimized, resulting in a 17% increase in oil production and 95% increase in the NPV, with a risk index of 0.40. This justifies performing a polymer flood.
The most promising scenario is the combined infill drilling and polymer injection, which significantly improved the economic indicators—30% increase in oil production, 230% improvement of the NPV over the base scenario, with a risk index of only 0.41.
The results of this study demonstrate that the combination of EOR with different operational strategies results in significant benefits compared to the individual scenarios. Analysis of just oil production independent of economics and risk can be misleading. Infill drilling or flooding should no longer be the question. Instead, the question should be how they can be properly combined at various stages of asset life.
Baker Hughes drilled one horizontal well for major Indian operating company in a, low resistivity contrast field, onshore India. The candidate field / basin is a proved petroliferous basin, located in the northeastern corner of India.
The scope of work for this project involved integrating geological and open hole offset parameters to build a Geosteering model. Integrated data included a study of offset well data from the field, regional and local dip analysis from wellbore images, and a review of structural maps. Successful integration of these data helped to steer the well in the desired zone as per plan and make the best use of the data and to reduce uncertainties in Geosteering, drilling. Although high-quality 16-sector images commonly yield bedding dip, fracture and other geological information, this paper emphasizes how real-time reservoir navigation decisions was made using Geosteering modelling, real-time image processing, dip picking study etc.
The key objective of this study was to develop a high resolution wellbore stability model for planned highly inclined development wells of an ultra-deepwater field through integrating geological, geophysical, petrophysical and drilling data to design optimized drilling mud weight window.
This study describes a customized high resolution wellbore stability modelling process for development wells in ultra-deepwater setting, where shale and sandstone have different pore pressure and stress magnitudes. Un-calibrated and calibrated seismic velocities along with offset well data were used to generate the high resolution pore pressure model for the overburden shale section. Laboratory based geo-mechanical tests, petrophysical logs and offset well events were integrated for the estimation of sub surface stresses and rock mechanical properties for overburden shale and sandstone. Subsequently, separate wellbore stability model was built to estimate the shear failure gradient for overburden shale and sandstone.
This study suggests that the mud weight (MW) window in the overburden is primarily governed by two parameters – (i) sand-shale pressure equilibrium state, and (ii) stress anisotropy. The intervals where the sand and shale are not in pressure equilibrium state (i.e. shale pressure > sand pressure), the minimum MW requirement is defined by either pore pressure or shear failure gradient (SFG) of shale formation. Whereas, maximum limit is marked by fracture gradient of relatively less pressured sand formation. Therefore, in such intervals mud weight window becomes much narrower (~1 ppg) than those intervals where sand and shale is in pressure equilibrium (~1.6 ppg). This study also highlights the increase of minimum MW requirement (SFG) in some intervals having relatively higher stress anisotropy. The minimum MW requirement within the main reservoir section having thin intra-reservoir shale is controlled by the SFG of the sand formation, as strength is lower in the reservoir sand than intra-reservoir shale. Results show the importance of high resolution modelling in order to capture pressure uncertainty, thin sands, sand/shale pressure equilibrium state, stress anisotropy and its effects in defining the optimum mud weight window. Based on analysis, further risk zonation was done to highlights intervals prone to wellbore collapse and mud loss.
This paper illustrates how the integrated high resolution wellbore stability modeling would help in optimum mud weight planning for highly deviated / horizontal wells to minimize the drilling risks and non-productive time (NPT), especially for challenging field development settings (deepwater, ultra-deepwater, high stress, High pressure High temperature).
PY-1 is one of the few fields in India producing hydrocarbons from Fractured Basement Reservoir. The field was developed with nine slot unmanned platform with gas exported through a 56 km 4" multiphase pipeline to landfall point at Pillaperumalnallur. Field was put on production in November 2009 with three extended reach wells. The production performance of the field had some surprise and declined earlier than expected. As a result, based on the conclusions drawn from an integrated subsurface study, a two wells reentry campaign to side track wells Mercury and Earth was planned to be executed in Q1 2018. The objectives of this paper are twofold: 1. Review the production performance of a granitic basement gas field and share learnings which may be useful for similar fields being developed elsewhere.
Biswal, Debakanta (Adani Welspun Exploration Limited) | Nedeer, Nasimudeen (Adani Welspun Exploration Limited) | Banerjee, Subrata (Adani Welspun Exploration Limited) | Singh, Kumar Hemant (Indian Institute of Technology)
The boundary between a thick carbonate layer and its substrata is often a well-defined reflector due to the presence of shaly and clayey layers beneath the carbonates. This reflector and other underlying reflectors result in a velocity pull-up effect because the seismic velocities within the carbonates are higher than that of the surrounding sediments. The geometry of velocity pull-up beneath the carbonate body is related to the geometry of the structure and the thickness of the carbonate body the seismic wave travels through.
In B9 area of Mumbai Offshore basin, the reservoir facies are largely represented by clastics deposited along tidal deltaic lobes. Wells drilled though Daman formation have encountered good quality pay sands within the Daman formation. This pay has produced commercial quantities of hydrocarbons in the vicinity making the area attractive for further exploration and exploitation. The overlying Bombay formation consists mainly of shale with occasional bands of limestone and claystone. The development of thick isolated carbonates bodies within Bombay formation is observed in "C" structure on which "Well-C" is placed. This is seen to significantly constrain the structural configuration in the "C" area. There is a possibility of substantial extension of the "C" structure towards south if the impact of velocity pull up due to carbonate build up can be successfully mitigated. The ultimate challenge is to image the Daman reservoirs, mitigating overburden lateral velocity variations.
In addition to a layered cake depth conversion approach for depth conversion of the time map, a more robust approach, PSDM followed by depth conversion was carried out. This paper highlights the merit of different methods.
This paper evaluates the impact of decision making and uncertainty associated with production forecast for 2000+ wells completed in Permian basin. Existing studies show that unconventional reservoirs have complex reservoir characteristics making traditional methods for ultimate recovery estimation insufficient. Based on these limitations, uncertainty is increased during the estimation of reservoir properties, reserve quantification and, evaluation of economic viability. Thus, it is necessary to determine and recommend favorable conditions in which these reservoirs are developed.
In this study, cumulative production is predicted using four different decline curve analysis (DCA) − power law exponential, stretched exponential, extended exponential and Duong models. A comparison between the predicted cumulative production from the models using a subset of historical data (0-3months) and actual production data observed over the same time period determines the accuracy of DCA's; repeating the evaluation for subsequent time intervals (0-6 months, 0-9 months,) provides a basis to monitor the performance of each DCA with time. Moreover, the best predictive models as a combination of DCA's predictions is determined via multivariate regression. Afterwards, uncertainty due to prediction errors excluding any bias is estimated and expected disappointment (ED) is calculated using probability density function on the results obtained.
In this paper, uncertainty is estimated from the plot of ED versus time for all wells considered. ED drops for wells having longer production history as more data are used for estimation. Also, the surprise/disappointment an operator experiences when using various DCA methods is estimated for each scenario. However, it appears that whilst Duong (DNG) method always overpredicts, power law exponential (PLE) decline mostly under predicts, the stretched exponential lies between DNG & PLE estimates and the extended exponential DCA demonstrates an erratic behavior crossing over the actual trend multiple times with time. In conclusion, profitability zones for producing oil in the Permian basin are defined implicitly based on drilling and completion practices which paves the path to determine the "sweet spot" via optimization of fracture spacing and horizontal length in the wells.
The outcome of the paper helps improve the industry's take on uncertainty analysis in production forecast, especially the concept of expected disappointment/surprise. This study suggests that effects of
This study presents a novel, integrated workflow to maximize recovery using PVT compositional modeling, history matching, and numerical reservoir simulation in a tight oil sand formation, the Second Bone Spring. Advancements in unconventional resource development have enabled the Delaware Basin to become highly significant. However, optimizing the development of each formation is still lacking in understanding. This study is one of multiple future studies over tight reservoirs in the Delaware Basin and exhibits a comprehensive approach. Properties that will be optimized are well spacing, reservoir parameters, and EOR feasibility.
To determine the behavior and optimize the development of each of these reservoirs, data from multiple sources was necessary. The data compiled consisted of reports from PVT analysis, completions design, petrophysical analysis, daily production and pressure, deviation surveys, structure and isopach maps, and well design. This data was then implemented into a 3D numerical reservoir simulator (CMG-GEM), first to confirm PVT output in a compositional simulation (CMG-WINPROP), then to simulate up to 20 years of production, and finally to use uncertainty analysis (CMG-CMOST) to optimize reservoir input parameters. Once a base case scenario was established, we then furthered our investigation of well spacing and EOR feasibility by setting up multiple different scenarios for each and running them for 20 years. EOR scenarios included 1-3 month huff-and-puff CO2, as well as low salinity water injection. Results are normalized per foot of completely lateral length and lab data is implemented in EOR simulations.
Our results confirm that reservoir parameters, once established after uncertainty analysis, have a large impact on both optimizing well spacing and EOR feasibility in the Second Bone Spring formation. With each well having very similar cluster spacing, proppant amount and type, and fracturing fluid and type, up to 250 feet of inter-well spacing is unaccounted for. Optimized models show that closer spacing of at least 150 feet can increase EUR estimates an average of 11.25%. An increase of 5-17% recovery is observed once a smaller spacing is implemented. EOR models showed that CO2 and low salinity water injection are viable candidates for the formation (7.25-9% increase for CO2, 6.25% for LSWI).
This integrated study refines our reservoir parameter estimates and helps identify potential to maximize recovery. It suggests that a tighter spacing is necessary to cover a larger portion of the reservoir, as well as showing that EOR is feasible. An improved understanding of the entire reservoir leads to better production and economic estimates.
S field has unique geological condition, the depth of maturity based on geochemistry analysis start from 800 m and classified as shallow depth rather than in the core of Kutai basin at 4000 m. It was caused by gravity tectonic from north which lifting the middle miocene formation from below. This situation gives the benefit to find source rock in shallower depth for unconventional exploration.
To characterize and predict the source rock especially for Total organic content value is using a well-known method called ΔLog R. This technique has been applied in many field with success stories. Beyond it is success, this method is less recognizing to predict in coal, because of the huge separation between Porosity log and Resistivity log. This study aims to applied this method in delta plain environment with abundant of coal source rock using between Density log, Sonic log, and Neutron log combine with Resistivity log. Besides that, TOC accumulation will be compared with Cyclostratigraphy trend, which trends contain much TOC content and by this vertical distribution to generate lateral correlation.
Basic principle for ΔLog R method is to seek the overlay between porosity log and Resistivity Log. Assuming when TOC is high the sediment rocks has good porosity and higher Resistivity reading. Those are the effect from kerogen in shale and generation of hydrocaron. In immature organic rocks it has good porosity but Resistivity log shows lowest value. Most of organic accumulation is in non reservoir. To eliminate the reservoir zone by using the Gamma ray log. This TOC value will be validate using several geochemistry analyses from cores.
Cyclostratigraphy-INPEFA log, is cyclic deposition that refer to orbital change that effect insolation on earth. This situation cause fluctuates of Eustachy and change the sea level. When sea level drop or N-Trend and coarse sediment will deposit and the other hand P-Trend or warming phase. Predicted TOC accumulation is much higher when warming phase. This trend will help to know TOC distribution around the field.