Effective management of Voidage Replacement Ratio (VRR) throughout the producing life of an oil reservoir is essential for achieving optimal oil recovery. VRR is quantitatively defined as injection/production fluid volume ratio at reservoir conditions. The primary goal in managing voidage replacement is to replenish the energy in a reservoir to a degree that the producing wells yield hydrocarbons at economical rates. The determination of VRR, however, becomes more complicated when reservoirs are significantly affected by fluid influxes. This paper presents a method developed to optimize VRR calculations using streamlines, traced from finite-difference reservoir simulation model outputs.
Good reservoir management practice necessitates that conventional VRR should be maintained at or above unity. Maintaining appropriate injection performance is therefore an essential requirement for achieving optimal oil recovery in secondary recovery processes. This can be achieved through effective VRR surveillance, water breakthrough monitoring, and reservoir pressure maintenance.
This paper presents a new technique and associated workflow for rigorous VRR determination that resolves a number of shortcomings inherent in conventional VRR analysis. This rigorous VRRR determination methodology was applied to an existing field with considerable operating history including multiple displacement and recovery processes: primary depletion, aquifer influx, gas re-injection, gravity water injection, and power water injection. This new methodology utilizes finite difference reservoir simulation models to generate streamlines from the pressure field and fluxes. Streamlines represent flow paths between injectors and producers. The streamline trajectories with associated time-of-flight values thus obtained take into account geologic complexity, external fluxes, well locations, phase behavior, and reservoir flow behavior. Rigorous VRR estimates are obtained by accounting for the influxes and well allocation factors (WAF), which represent a measure of connectivity between specific injector/producer pairs with associated fluxes. The fluxes and WAF values are calculated automatically from the history-matched reservoir simulation model during streamline tracing for associated time steps.
Traditionally, the well VRR values are calculated via the formulation of well inflow performance relationship (IPR), which may result in suboptimal estimations by not accounting for external sources of energy, such as influx from neighboring zones. The presented approach allows for improved optimisation of waterflood injection efficiency, where the off-set oil production can be derived directly from reservoir material balance (MB) calculations and streamline-generated well allocation factors. In order to facilitate VRR calculations with dynamic simulation regions, we propose a workflow for streamline (SLN) based VRR calculations using the time-dependent flow-based SLN-conditioned drainage volumes, automatically extracted from the simulation grid and iteratively incorporated into simulation model constraints as a function of simulation run time-steps.
Well RXY is located in Cairn’s Ravva offshore field in the Krishna-Godavari Basin in India. One goal for the field was significant crude production by means of a secondary reservoir section. This paper summarizes key engineering discoveries and technical findings observed during the execution of 200 hydraulic-fracturing diagnostic injection tests in the Raageshwari Deep Gas (RDG) Field in the southern Barmer Basin of India. Reliance Industries and BP are going forward with the expansion of a huge field off the east coast of India that is expected to fill 10% of the country’s energy needs. India Asks Big Oil Companies "Where Do You Want to Drill?" India will test whether it can reach its ambitious goal of reducing oil and gas imports by 10% by 2022 with an upcoming auction of oil properties.
This paper summarizes a technology using SMP to provide downhole sand control in openhole environments. With multistage operations becoming the industry norm, operators need easily deployable diversion technologies that will protect previously stimulated perforations and enable addition of new ones. This paper reviews several aspects of the use of in-stage diversion. Development of a new polymer composite that degrades via hydrolysis in hot water or brine holds potential for use in structural applications for intervention-less downhole tools. The polymer-injection project in the Dalia field, one of the main fields of Block 17 in deepwater Angola, represents a world first for both surface and subsurface aspects.
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.
Learn more about training courses being offered. Learn more about training courses being offered. This course covers the fundamental principles concerning how hydraulic fracturing treatments can be used to stimulate oil and gas wells. It includes discussions on how to select wells for stimulation, what controls fracture propagation, fracture width, etc., how to develop data sets, and how to calculate fracture dimensions. The course also covers information concerning fracturing fluids, propping agents, and how to design and pump successful fracturing treatments. Learn more about training courses being offered. Current and future SPE Section and Student Chapter leaders are invited to engage and share. Every attendee leaves energised with a full list of ideas and a support network of fellow leaders. Those sections and student chapters actively participating in this workshop have consistently been recognized with awards as the best in SPE. SPE Cares is a global volunteering drive aimed at promoting, supporting and participating in community services at the SPE section and student chapter’s level. On its official launch this year at ATCE Dubai, SPE Cares will conduct a “Give a Ghaf” Tree Planting Programme to help preserve Ghaf’s cultural and ecological heritage. The Ghaf tree is an indigenous species, specific to UAE, Oman and Saudi Arabia. It is a drought tolerant, evergreen tree that can survive a harsh desert environment. The initiative not only aims to hold events/activities at ATCE, but also recognise community service that SPE members are already conducting in their respective student chapters and professional sections. The KEY Club, open daily, is an exclusive lounge for key SPE members. The lounge is open to those with 25 years or more of continuous membership, Century Club members, current and former SPE Board officers and directors, Honorary and Distinguished Members, as well as this year’s SPE International Award Winners and Distinguished Lecturers. DSATS (SPE’s Drilling Systems Automation Technical Section) will hold a half-day symposium featuring keynote presentations on urban automation. This symposium will explore technologies being used in developing smart cities through the automation of their infrastructure, transportation systems, energy distribution, water systems, street lighting, refuse collection, etc. These efforts rely on many of the same tools needed for drilling systems automation yielding increased efficiencies, lower maintenance and reduced emissions. Their knowledge and experience can guide the path being travelled by the oilfield drilling industry.
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
A hydrocarbon find has always been an exploration geologist’s adventure and has remained at the forefront of the E&P cycle for the survival of the oil and gas industry. Big and easy finds are a distant past; therefore, the quest has shifted to go beyond conventional sandstones and carbonates to more complex areas of unconventionals: low porosity, low permeability, low resistivity, tight and ultra-tight, HPHT, shale, CBM, gas hydrates, and any other possible regime including deeper, geologically complex, and seismically opaque features such as salt, basalt, sub-basalt, even basement.
Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.
Dutta, Sandipan (Cairn Oil & Gas, Vedanta Ltd.) | Kuila, Utpalendu (Cairn Oil & Gas, Vedanta Ltd.) | Naidu, Bodapati (Cairn Oil & Gas, Vedanta Ltd.) | Yadav, Raj (Cairn Oil & Gas, Vedanta Ltd.) | Dolson, John (DSP Geosciences and Associates LLC) | Mandal, Arpita (Cairn Oil & Gas, Vedanta Ltd.) | Dasgupta, Soumen (Cairn Oil & Gas, Vedanta Ltd.) | Mishra, Premanand (Cairn Oil & Gas, Vedanta Ltd.) | Mohapatra, Pinakadhar (Cairn Oil & Gas, Vedanta Ltd.)
The Eocene Lower Barmer Hill (LBH) Formation is the major regional source rock in the Barmer Basin rift, located in Rajasthan, India, and has substantial unconventional shale potential. The basin is almost completely covered with 3D seismic, providing an opportunity for more surgical mapping of the rapid structural and stratigraphic changes typical with any syn-rift deposit. Thick sections of organic-rich black shales reaching 400 meters thickness with TOC up to 14 wt. %, were deposited during a period of widespread basin deepening. Algal-rich type I oil prone kerogens dominate in north and generate oil, with very little gas. These shales mature at much lower temperatures than the mixed type I and III kerogens in the south, which also generate much larger amounts of gas and oil, and at higher threshold temperatures. The variable kinetics, as well as rapid facies variations typical of rifts, provide challenges to high-grading and testing unconventional shale plays.
Extensive Rock Eval pyrolysis and source rock kinetic databases were combined with petrophysical analysis to determine log-based porosity and saturations and productive potential. Modified Passey techniques calibrated to NMR log porosities provide estimates of organic richness as well as maturity and shale oil saturation. Basin modeling using Trinity software provides probabilistic ranges of generated and expelled hydrocarbons to determine storage capacity. The modeled oil window storage capacity varies between 6 to 13 MMBOE/km2, comparable to the values observed in Eagle Ford and Barnett Shale plays, but in a rifted basin and not broad cratonic shelf deposits.
Excess pore pressure was modeled using the kinetics of kerogen-to-oil conversion, and is noted in some of the deeper wells in tight sandstones, but not confirmed in the undrilled grabens. These pressure-gradient maps, along with oil properties (viscosity and oil mass fractions) derived from the geochemical model, are used to compute the producibility index. Composited storage capacity and producibility index maps have high-graded potential pilot areas.
In contrast to cratonic shale plays such as the Bakken or Eagle Ford, rapid and substantial facies variations occur due to local input of clastics and variable turbidite geometries which form potential targets for horizontal drilling. Increasingly more detailed paleogeographic maps are highlighting both the challenge and potential of the rich source rock in this basin.
This paper will cover how geochemical, structural, paleogeographic, petrophysical and other data are being used to derisk unconventional potential in this rich and complex rift system. Learnings from future testing of the Barmer Basin shale plays will be important to understand how to develop shale plays in other lacustrine rift basins.
Application of horizontal wells and multi-stage fracturing has enabled oil recovery from extremely low permeability shale oil reservoirs, but the expected ultimate recovery (EUR) due to depressurization is only 5-10% of the original oil in place (OOIP). The objective of this work is to test whether coupling a chemical treatment with CO2 huff-n-puff can improve the oil recovery. The chemical blend (CB) contained an anionic surfactant and a persulfate compound in brine. Oil recovery efficiency of the CO2 with the chemical blend was compared with CO2 Huff-n-Puff cycles at different pressures (5200 psi, 4000 psi and 2800 psi). Outcrop Eagle Ford and Mancos core plugs were used in the study. This work shows that CO2 huff-n-puff is an efficient technique to improve oil recovery from oil shales. Most of the added oil was recovered in all the experiments. The pressure to which the cores were pressurized with CO2 did not affect the oil recovery significantly as long as it was high enough (2800 psi in these experiments). The addition of chemical blend seemed to impede the oil recovery. Because of the heterogeneity in shale samples, more experiments need to be conducted to understand and validate these conclusions.
Shale oil contributes more than 60% of the US oil production according to EIA (2019). Shale oil production has been feasible because of technological development for horizontal wells with multi-stage hydraulic fracturing. The hydraulic fracturing technique has improved significantly in recent years, but the estimated oil production in these unconventional reservoirs is less than 10%. For an average well, the oil production rates fall sharply in the first year (more than 75%) because of the extremely low permeability, microfracture closure, and large flow resistance at the matrix-fracture interface. To keep the sustainability of oil production from shale oil, it is essential to develop enhance oil recovery (EOR) techniques for unconventional reservoirs. There have been several investigations on surfactant-based treatments, water injection and CO2 huff-n-puff for shale EOR.