SPE is educating the next generation of aspiring engineers, scientists and managers about the oil and gas industry. This is an opportunity for school students in grades 9–12, studying Mathematics, Physics, Chemistry, Geography or interested in Petroleum Engineering are invited to join SPE members from all over the globe to discover the world of Petroleum Engineering. School teachers are invited to bring a group of 10–15 students. Students will be treated to a range of hands-on activities and presentations from renowned engineers. The oil price outlook coupled with the response of each oil and gas company to make ends meet has led to severe exploration budget cuts.
Reservoirs which produce under active water drive offer a significant uncertainty towards implementation of Chemical EOR processes. This paper describes a successful pilot testing of ASP process in a clastic reservoir which is operating under strong aquifer drive. The field has ~ 30 years of production history. The objective of the pilot was to understand response of ASP process in a mature reservoir, which is operating under active edge water drive. The build-up permeability of the reservoir is 2-8 Darcy with viscosity~ 50 cP. Salient key observations like production performance, incremental oil gain, polymer breakthrough etc. are discussed in this paper after completion of the pilot.
On the basis of laboratory study and simulation, ASP pilot was implemented in the field in 2010.The pilot was designed with single inverted five spot pattern and one observation well. The pilot envisaged injection of 0.3 pore volume (PV) Alkali-Surfactant-Polymer (ASP) slug, 0.3 PV graded polymer buffer followed by 0.4PV chase water. The pilot was meticulously monitored for production performance and breakthrough of chemicals. All the pilot producers have more than 20 years of production history. Base oil rate and water cut were fixed before start of the pilot, on the basis of test data which was used to monitor pilot performance. Interwell Tracer Test (IWTT) was conducted before starting of ASP injection so as to understand sweep in the pilot area. In addition, quality of injection water and chemical concentration in ASP slug was checked regularly to ensure best quality.
Significant response of the pilot was observed within 15 months of the start of the pilot which was published in 2012. This paper aims to describe the learning and conclusion after successful completion of the pilot. ~40-50% jump in oil rate was observed during the ASP injection period which sustained for 12-18 months. However preferential breakthrough of ASP slug in one of the producer impacted the incremental oil gain. The preferential breakthrough of polymer was due to presence of high permeability streaks which was rectified by profile modification job. In addition, strong aquifer movement was experienced during ASP injection which leads to rise in water cut of a pilot well. However, the pilot well was restored through water shutoff jobs. After completion of ASP and mobility buffer, a cumulative incremental oil ~28000 m3 was obtained. Cumulative incremental oil gain is in line with simulation studies prediction. 12-14% decrease in water cut was observed which sustained for ~ 6-18 months. Regular monitoring of produced fluid indicated breakthrough of polymer and alkali in 2-3 producers. During the pilot, produced fluid handling issues like tough emulsion formation, lift malfunctioning etc. was not observed. These collective observation indicated success of the ASP pilot project.
There are very few case histories of successful ASP pilot implementation are available, in which the reservoirs has been operating under active aquifer drive. Learning of this ASP project can be taken forward for expansion of ASP flood and also designing of ASP pilot/commercial projects for analogous reservoirs.
Digital core generated from micro CT images of rock sample cutting and results obtained from digital core analysis are presented in this work as a substitute of conventional core study for Petrophysical evaluation. Conventional core extraction during drilling, core preservation and analysis are expensive, time consuming processes and often unavailable for small size fields. Moreover, routine and special core analysis results are a critical input for petrophysical characterization. In this situation, digital core study appears to be a cost effective substitute to ensure and validate petrophysical evaluation results.
High resolution 3D micro CT imaging and analysis was done on rock samples cut during drilling or on sidewall core plugs cut by wireline logging tool. Segmented micro CT image slices when combined in 3D space in three orthogonal directions, can be termed as digital core. Solid rock matrix, clay filled and porous rock portions are distinctly separable using micro CT images and their volume fractions can be estimated. Detail textural analysis in terms of Grain and pore throat size distribution of the rock is possible from digital core which controls storage capacity and flow behavior. Two critical petrophysical input parameters for fluid saturation (Sw) estimation are cementation exponent (m) and saturation exponent (n). These parameters are commonly computed from special core analysis (SCAL) on conventional core plugs. But digital core study can provide the estimates of ‘m’ and ‘n’ which replace the need of SCAL.
Digital core study has been carried out in three different reservoirs in west and east coast of India and the results were analyzed. Porosity and permeability data obtained from digital core was first compared with log analysis results and then used to identify different petro physical rock types (PRT). Fluid saturation (Sw) was estimated from resistivity log by using ‘m’ and ‘n’ exponent obtained from digital core seems to be more realistic and corroborates with well test results. Porosity, permeability, water saturation and rock types (PRT) were helped to build geo-cellular model (GCM) for small and marginal reservoir.
Enhanced reservoir characterization by using digital core study result has helped in better understanding and decision making for small and marginal fields where limited well data is available. Finally this leads to the preparation of field development plan (FDP). Digital core technique is less expensive, having quick turnaround time than conventional coring which has translated into high value business impact for any development project.
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.
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.
This paper attempts to use analogs of coals and Coal bed Methane (CBM) properties in Sedimentary basins to mutual advantage from the knowledge of each other.
An attempt has been made here to showcase as to why two Coal bearing formations, Lower Eocene, Cambay in India and Miocene, South Sumatra, Indonesia can be compared with each other in terms of coal quality and CBM characteristics.
Cambay basin, with an area of 56,000 sq kms is an elongated NNW-SSE rift basin in the western part of India. The basin fill comprises Mesozoic(?) sediments capped by Late Cretaceous Deccan volcanics and a thick tertiary pile of fluvio deltaics. Thick Lignite to sub bituminous coal is found in Middle (two thick seams) and Lower Eocene section (three thick seams of 20-35 m range and one thin seam of 1-10m). Chemically, the Middle Eocene lignite-sub bituminous coal is characteristically low in moisture (4-5%), quite low in ash (1-11%) and high in volatiles (43-55%). The Lower Eocene coals are sub bituminous with 10-20% moisture, low ash(5-10%), low Sulphur(<1%) content. The gas content of the Lower Eocene coals are 6 cubic metre / tonnne, with permeability 1-3 Md with seams slightly over pressured. Depth ranges of both these coal horizons are between1000-1800m approximately.
South Sumatra basin, double in size wrt Cambay basin with an area of 100,000 sq kms, is a NE-SW trending, backarc basin. Series of half grabens punctuated with basement highs, holds Miocene and Eocene Coals in the grabens of a mostly Tertiary sedimentary pile. The Miocene coals (formed in tide dominated coastal plain) are sub bituminous, with VRo 0.4-0.5, low ash(<10%), Moisture(10-18%), high volatile matter of around 40% at depths 300-1000m, with 20-30 seams with gas content of 7 cubic metre / tonne. The Older Eocene Coals are1-10 m thick at depths 1000-2000m formed in peat bogs in fluvial settings.
The Indonesian Coals of Miocene age are very comparable in coal properties and gas content to the Middle and Lower Eocene Coals of Cambay basin and can supplement each other in studies for CBM exploration and exploitation. Of great similarity are the coal quality, ash% and gas content. To take the comparisons further ahead, detailing of thickness, extent, geometry and depositional environments of each of these basins would be advantageous.
Shiwang, Rahul (Baker Hughes, a GE company) | Banerjee, Anirban (Baker Hughes, a GE company) | Ramaswamy, Vijay (Baker Hughes, a GE company) | Malik, Sonia (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company) | Kumar, Sanjeev (ONGC Ltd.) | Chadha, A. K (ONGC Ltd.)
The identification of fluid saturations in depleted reservoir sands is critical to understand the reservoir potential and field life. However, in case of water flooding, the formation water salinity of the reservoirs sands might be altered and fluid saturations from conventional petrophysical analysis can be misleading. This will have direct impact on the field economics. A salinity independent saturation computation from Carbon/Oxygen (C/O) log becomes a necessity in such development wells– a first of such application in a field under secondary recovery for this basin.
C/O well logging has been extensively used in cased hole environments to determine saturation behind casing. They are used essentially to determine oil saturation in cased hole conditions for depleted reservoirs. While their cased hole applications have been well established; for the study well, a pulsed neutron tool was used in an open hole environment to determine the fluid saturations to compare against the saturations computed from conventional resistivity logs. This study helped in the determination of fluid saturations in mixed salinity reservoir sands, which were to be explored from subsequent wells in the field.
The hydrocarbon-bearing sands in the field were water injected in nearby wells to enhance recovery. Development wells drilled in the field relied on petrophysical evaluation from conventional open hole data and pressure testing and fluid sampling depths were determined accordingly. A pulsed neutron tool was deployed in an open hole well after operational constraints were encountered with the formation testing tool. As an alternative, the pulsed neutron data were acquired in the well to compute salinity independent water saturation based on C/O log response as against the fluid saturation computation from resistivity logs. The determination of fluid saturations from C/O helped in determination of altered salinity for the sand intervals in the field. For the study well, C/O-derived water saturation was found to be higher than that from resistivity log computation. This was significant in identification of water breakthrough in the bottom interval of the reservoir sands.
This paper details the method and findings of C/O logging in open hole environment from Western Onland Basin in India. The critical solutions provided for the reservoir sands in the field and enabled the operator to save significant well cost and rig time by making informed decision of not lowering the casing in this well section.
Mishra, Gaurav Kumar (Oil and Natural Gas Corporation Limited) | Meena, Rakesh Kumar (Oil and Natural Gas Corporation Limited) | Mitra, Sujit (Oil and Natural Gas Corporation Limited) | Saha, Kunal (Oil and Natural Gas Corporation Limited) | Dhakate, Vilas Pandurangji (Oil and Natural Gas Corporation Limited) | Prakash, Om (Oil and Natural Gas Corporation Limited) | Singh, Raman Kumar (Oil and Natural Gas Corporation Limited)
India is the fastest growing major economy and third largest CO2 emitter in the world. Keeping cognizance of country's energy requirement and commitment to climate change, embarking upon technologies having minimal carbon footprint is the need of the hour. Carbon capture, utilization and storage (CCUS) is one such technology which offers dual benefits of carbon sequestration & enhancing oil production from mature oils fields. This paper outlines ONGC's efforts in bringing nation's first CO2-EOR project.
In view of non-availability of natural CO2 sources in India, usage of anthropogenic CO2 captured from thermal power plants was conceptualised. Based upon CO2 source-sink matching exercise and favourable reservoir & fluid parameters, two oil fields were screened. Technical feasibility of CO2-EOR was first ascertained in laboratory by determination of minimum miscibility pressure (MMP) of CO2 through slim tube experiments. Encouraged by laboratory results, full field compositional simulation studies along with fluid characterization inputs from PVT simulator were carried out.
The MMP were found to be in range 190-250 Ksc, which is below the initial reservoir pressures of the targeted reservoirs. The proposed scheme entails drilling of around 70-80 wells inclusive of both producers & injectors and has the potential to yield an incremental recovery between 10-14 %. A sensitivity analysis based upon purity of CO2 and its adverse effect on MMP was carried out in terms of reduced oil recoveries. Since, this shall be a CCUS project, CO2 from the produced stream has to be separated, compressed and reinjected in a closed loop system. Around 5-8 MMT of CO2 will be sequestrated through Structural, Solubility and Residual trapping mechanisms as modelled in compositional simulator. IFT reduction & decrease in Sor (Residual oil saturation) as result of swelling, miscibility of CO2 with native oil were also modelled in simulator. Being first of its kind project in India, there are many inherent challenges to the CCUS project. At the source end, capturing CO2 from flue gas stream and its compression & transportation is a cost and energy intensive process. At the Sink end, CO2 being acidic and corrosive gas will need retrofit modifications in terms of special corrosion resistant metallurgy for existing processing facilities.
The learning curve from this endeavour shall create knowledge base to further expand deployment of CCUS in India, bringing a large portfolio of reservoirs under the ambit of CO2-EOR. Success of CCUS in India will not only increase domestic oil production but also cater to address the National INDC of reducing emission intensity of GDP by 33-35 percent by 2030 as per Paris agreement.
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.