Oligocene

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.

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

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.

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 describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.

Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.

This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.

In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.

An interpreted late Oligocene/early Miocene submarine channel system is imaged using 3D seismic data. The seismic stratigraphic features are subtle and thus impossible to map for long distances using traditional inline/crossline interpretation. In order to understand the extent of the features, key horizons are mapped using traditional methods, and data extracted from the seismic volumes using horizon slices in order to view the data in plan view. This illuminates the vast network of channels and fanlike features of the system. Due to the varying tuning thicknesses of the features, spectral decomposition and image blending is utilized to create an enhanced composite image of the system features (Figure 1). From this, we observe that local structural controls have a large influence on the deposition of the system and the directional flow of the channels and fan-like features.

Presentation Date: Wednesday, October 17, 2018

Start Time: 8:30:00 AM

Location: 211A (Anaheim Convention Center)

Presentation Type: Oral

Cuu Long basin is a Cenozoic rift basin located in the southeastern shelf of S.R. Vietnam, containing vast potential oil and gas resources. The basin was impacted by three main tectonic periods of pre-rift, syn-rift and post-rift tectonism. Major petroleum plays in Cuu Long basin are the Pre-Cenozoic fractured basement, Oligocene and lower Miocene sandstone reservoirs. Upper Oligocene sediments were deposited during late syn-rift phase of Cuu Long basin. The reservoirs in these strata (Oligocene C and D) were previously discovered in the center, southwestern and southeastern margins of Cuu Long basin with limited total reserves, up to 5%, of Cuu Long basin's discovered reserves. Recent exploration and appraisal results of St, Tg, Rg, Ct etc. show a greater potential of upper Oligocene reservoirs with a greater variety of trap types in many areas of Cuu Long basin than that of previous assessments. Therefore, additional studies and assessments of recently discovered trap types need to be carried out for the Cuu Long basin exploration and appraisal program. This article discusses the assessments of upper Oligocene trap types and identifications of several trap mechanisms utilizing the integration of exploration methods. The research results permit better understanding of the trapping mechanisms and possible distributions of various trap types in the upper Oligocene strata of the Cuu Long basin, thus leading to better planning of exploration/appraisal strategies in the basin.

ABSTRACT: In this paper, we report on a scoping study that was prompted by operational issues through an Oligocene smectite-rich shale that involved changes in borehole inclination with respect to the bedding. A core characterization workflow is used to specifically probe geomechanical heterogeneity and anisotropy for static and dynamic elastic properties as well as failure strength. Initial petrophysical scanning of the core surface provides a first indication of existing heterogeneity for properties of interest and assists in devising an efficient sampling strategy. Over the three-foot section analyzed, and despite its apparent homogeneity, the core exhibits a two-fold variation in reduced Young’s modulus between softer and stiffer zones, which is tied to slight changes in carbonate content. Confined elastic and mechanical measurements reveal strength anisotropy of the order of 20% and P-wave and S-wave velocity anisotropies of about 20% and 30%, respectively. Moreover, testing shows that the shale is weakest at oblique angle to the bedding due to weak bed parallel surfaces which activate when favorably oriented. These results suggest that anisotropy and heterogeneity both need to be accounted for in borehole stability models involving smectite-rich material.

1. INTRODUCTION

Accurate wellbore stability prediction in geomechanically unstable formations requires thorough understanding of the drilled rock properties. This includes the ability to predict failure in deviated wells associated with bedding heterogeneity or to better assess the relationship between intrinsic elastic properties and stress/strain boundary conditions for e.g. in situ stress computations and log-based geomechanical forecasting.

This paper presents a geomechanical core analysis workflow that includes petrophysical core scanning for heterogeneity assessment and sample picking, as well as geomechanical testing for anisotropic static/dynamic elastic properties and strength. In particular, the petrophysical scanning includes a mechanical probe called the Impulse Hammer which functions by analyzing the force-time function of a hardened steel sphere mounted on an accelerometer dropped on the surface of the rock. This analysis produces a reduced Young’s modulus at a resolution on the order of the millimeter revealing fine scale heterogeneity. Using the profiles obtained during petrophysical scanning, locations of interest can be chosen for further geomechanical evaluation on plugs.

Panna field is located in the western offshore region of India and produces oil and gas from Middle Eocene and Early Oligocene Bassein limestone. Production is taken mostly through 3 ½" or 4 ½" tubing through a packer set in 7″ liner. The Panna-Mukta-Tapti Joint Venture (PMT JV) took up a plan to revive wells addressing well integrity issues and limitations associated with old completion jewelry for increasing the production.

Work-over campaign was planned for four wells on PB and three wells on PC platform to enhance production. The plan was to cut and retrieve the old completion and tubing above the 7″ permanent packer and install improved completion, having facilities of Permanent Down Hole Gauges (PDHG), Gas Lift Mandrel (GLM) and Chemical Injection Mandrel (CIM) through an additional packer set in 9-5/8″ casing.

In line with two barrier philosophy, two plugs were set inside the production tubing, one at TRSSV (shallow-set) and another one below the production packer (deep-set). The plug below the production packer doubled-up to also hold back the workover fluid, which may have hampered the productivity of an already sub-hydrostatic reservoir, if losses occurred. However, at the end of workover operations, the retrieval of this deep set plug could not be done even after various attempts and spending valuable rig time. This problem was faced with three out of the first four wells, which proved to be a challenge and forced the team to devise a new strategy for remaining wells.

At this point, an ingenious solution was devised to employ Plasma Based Punctures (PBP) to puncture the tubing in the limited space between the packer and the deep set plug to kick back the wells into production. Rig based PBP operations were carried out on two PC wells and Rig less PBP operations were carried out on three PB wells to get them online post work over operation. This resulted in saving several hours of rig time as the deep set plugs could not be retrieved in the conventional planned slick line operations.

This paper intends to highlight the challenges faced, and how PBP proved to be the optimum solution, by simplifying operations and ensuring the timely delivery of production.

The PBP operations proved viable through savings on energy, resources, time and cost associated with work-over jobs. The potential savings were roughly 780,000 bbls of oil which were significant for the aging asset. It is therefore, a potent alternative to other costly solutions in a scenario that often fails to deliver objectives, as happened in this campaign.

Abstract

Application of openhole sand control technology is becoming mandatory in the field, particularly with the given uncertainty in geomechanics, challenges to wellbore integrity while drilling, and sand production during the life of the well. The completion equipment readiness and success of the installation can be challenging in the event of extending the horizontal section to accommodate geological heterogeneity and maximizing well productivity. This paper discusses operational excellence recorded in Well A, in the Thang Long Field, offshore Vietnam, from well design perspectives ensuring maximum reservoir contact to outcome of well completion.

The well was targeted in the Oligocene reservoir, a thin oil rim with large gas cap overlay, and required drilling and completion for 1126 m horizontal length of 8 1/2-in. open hole. The completion design included multiple swellable packers for isolation of unwanted zones, 6 5/8-in. basepipe sand screens for the production zones, and a fluid loss control device to help prevent undesirable losses. Several torque and drag simulations were performed to help predict potential threats that could be encountered during completion string deployment or during space out of the inner wash pipe string.

One apparent challenge of this completion design was to deploy the lower completion string to total depth (TD) per stringent reservoir requirements, resulting in an approximate 1126 m length of the string in the horizontal section. Another task was to facilitate manipulating 1130 m of wash pipe inside the completion string to locate the seal assemblies accurately at the corresponding seal bore extension positions for effective acidizing treatment. Although these were long sections of completion string and wash pipe, the quality of acidizing stimulation to effectively remove mud cake should not be compromised to ensure positive production rates.

During operations, the completion string was run to target depth without any issue, and the wash pipe was spaced out and manipulated correctly. These operations subsequently led to a successful acidizing treatment and the proper closure of the flapper type fluid loss device. The completion design and operation were concluded successfully, significantly contributing to field production performance to date.

The novelty of the completion design and installation is the ability to deploy an 1126-m lower completion in long, highly deviated and horizontal openhole section coupled with acid stimulation in reasonable time and as per plan.

Integrated geophysical applications and well datasets play an important role in understanding reservoir distribution and decision making for a robust development plan. A technical assessment was completed in a gas field in the North Malay Basin to describe the reservoir heterogeneity in the Early Miocene to Late Oligocene reservoir intervals. The field is a North-South oriented plunging anticline with stratigraphic trap configuration, discovered in 2007 by Well-X1. The assessment has resulted in a proposal of an appraisal well in 2014, Well-X2ST to delineate the northern hydrocarbon extent and to assess the hydrocarbon potential in the exploration interval of deeper sequences. The new well datasets were acquired and the results were utilized to further evaluate the field.

This paper focuses on the deepest reservoir sequence, DS12, encountered by the appraisal well in the eastern flank of the Malaysia-Thailand Joint Development Area (MTJDA). Rock physics modeling and seismic attribute datasets with well log and pressure data integration were utilized to better understand sand distribution for the upcoming development planning. Due to the thinly bedded nature of the reservoirs, the seismic could not be fully utilized to evaluate internal stacking geometries. This was further complicated by attenuation from the overlying thick shale. However, attribute analysis was effective to determine overall sand presence where the bed thickness ranges from 10 to 15 meters and the seismic detection limit is approximately 8 meters.

Rock property analysis was performed to calibrate both acoustic impedance and Vp/Vs to gamma ray for indication of sand presence. The Vp/Vs derivative was used instead of acoustic impedance because of the extra information obtained in both the elastic and AVO domain. In addition, rock physics modeling was performed to differentiate gas from wet sand and shale. The seismic datasets were used to qualitatively condition a geologic model to better distribute sand presence for well planning optimization. Development wells are planned to target good quality sands to maximize recovery efficiency

The success of proving the deepest reservoir sequence in the eastern flank of MTJDA, utilizing geophysical application and well data integration, have resulted in an improved understanding to outline deep reservoir distribution in the surrounding area and mitigate uncertainties in the development plan.