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.
Africa (Sub-Sahara) Eni has begun production from the Vandumbu field and made a new oil discovery in the Afoxé exploration prospect in Block 15/06 offshore Angola. First oil from the Vandumbu field, through the N'Goma floating production, storage, and offloading vessel, was achieved in late November, 3 months ahead of schedule. Vandumbu is approximately 350 km northwest of Luanda and 130 km west of Soyo. This, along with the startup of a subsea multiphase boosting system in early December, boosts oil production from Block 15/06 by 20,000 B/D. The rampup of Vandumbu is expected to be completed in 1Q 2019. Block 15/06 is being developed by a joint venture formed by Eni (36.84%, operator), Sonangol (36.84%), and SSI Fifteen (26.32%). Asia Pacific Ophir Energy's Paus Biru-1 exploration well in the Sampang production-sharing contract (PSC) offshore Indonesia has resulted in a gas discovery.
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.
Goyal, Mayank (Oil and Natural Gas Corporation Ltd) | Singh, Pramod Kumar (Oil and Natural Gas Corporation Ltd) | Parmar, Kishan J. (Oil and Natural Gas Corporation Ltd) | Pareek, Ramesh C. (Oil and Natural Gas Corporation Ltd) | Prasanna, Guru V. (Oil and Natural Gas Corporation Ltd) | Dey, Sumanta Kumar (Oil and Natural Gas Corporation Ltd)
Repairing or recompletion of gravel pack (GP) assembly in horizontal wells is a real challenge. Complete or partial retrieval of GP assembly and re-GP or re-makeup of part of its subsurface hardware is critical, time consuming, complicated and yet uncertain. Such jobs being complex in nature, the attempts often lead to abandonment of the well causing huge capital loss. This paper intends to highlight the success story of repairing GP assembly in a horizontal well in short span of time and reviving the well on production.
In-situ combustion (ISC) process, a thermal Enhanced Oil Recovery (EOR), is under commercial application in one of the heavy oil field of ONGC. To capture the combustion displaced oil and to improve the efficiency of ISC process, an unconventional horizontal oil producer (BL#XY) well drilled against 4° dipping reservoir with maximum angle of 94.8° showed exceptionally encouraging results. The well drilled with 300 m horizontal drain hole horizontal section of the well was completed with Gravel Pack (GP) using conventional lead seal assembly (LSA) as a part of over the top assembly stabbed at ~82.8° incli-nation to arrest sand incursion. The well was put on artificial lift mode (Sucker Rod Pump) for maximum designed liquid withdrawal of ~315 bbls/day. Under the effect of ISC, the well produced liquid at the rate of 1500 bbls/day with 30% water cut. After sustained production of few months, the well ceased to flow due to sand incursion. In depth analysis of flow behavior of the well & response of rig less interventions indicated that improper sealing of LSA at high angle could be the potential escape route of sand/gravel under the influence of high production rate leading to GP failure. This paper illustrates the details of initial completion, attempts made to revive the well, problems encountered during fishing GP Assembly, mid-course corrections adopted to recomplete the well with customized down hole assembly and new over-the top assembly. Meticulous planning and perfection in execution of work over operations resulted in successful repairing of GP and revival of the well.
A cross-over with 8 O-rings, an innovative and fit to the purpose tool designed & fabricated in-house along with the modified Bottom Hole Assembly (BHA) was latched co-centrically with the intact part of the assembly and then GP packer was set hydraulically. The integrity of the repaired GP assembly was tested and found OK. The well was put back on production with SRP mode of lift. Presently, the well is producing 500 bbl/d of liquid. The in-house engineering has revived an expensive horizontal well and saved significant expenditure.
This paper would be of interest to engineers and technicians associated with completion or gravel packing jobs and will provide them insights of such completions in highly deviated wells. It also provides an understanding of the importance of GP Packer setting depth and repairing of GP assembly in case of failure.
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.