TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA multi-disciplinary approach had been adopted to resolve the exploitation and development strategy for Deohal and its extension oilfield having mainly the deep Eocene clastic reservoirs which is geologically complex, over pressurized stack of thin sands [by 30-40 Kg/cm 2 (assuming 0.1 Kg/cm 2 /m hydrostatic gradient] interbedded with shale/ carbonaceous shale. An accurate delineation of individual sand in such reservoirs is beyond the resolution of seismic as these occur at a depth of 3600 to >4000 m and its thickness vary from 2 to 4 m only. The Lithostratigraphic correlation based on well log is often unreliable/ difficult due to thin and extreme heterogeneous nature of the sediments. Moreover, areal extent of reservoir as a single unit is difficult to ascertain. The petrophysical properties viz. porosity and permeability substantially deteriorate with increase in depth i.e. below 4000 m.Initially 3D seismic data was showing a broad faulted anticline with fault 500 m to 800 m away from the crestal part. Analyses of pressure transient data showed barrier nearby and reinterpretation of 3D seismic data confirmed the presence of minor faults having limited extension.The Paper presents how transient well test data in conjunction with static 3D seismic data, wireline log and dynamic pressure-production data have helped to workout development strategy for a geologically complex and heterogeneous Lower Eocene thin sand reservoir in one of the oilfields in Upper Assam Basin, India.
Gas lift is the process of injecting gas into the tubing at a predetermined depth in order to lift the crude oil to the surface. Gas lift is applied to a well when the reservoir pressure falls to such a level that it does not produce without application of external energy. There are mainly two types of gas lift which are Continuous and Intermittent gas lift. This paper deals with the theoretical determination of relationship between liquid accumulation and gas injection duration in an intermittent gas lift well and how this knowledge can be combined with the experience of Engineers to maximize the production of a well. In order to find the relationship between the given durations, a simple mathematical approach with the assumption that the gas injection time is independent of liquid accumulation time is followed. We, then apply various tools of mathematics such as the principles of maxima and minima, Leibnitz theorem, definition of the slope of a line etc. to finally prove the interdependence of liquid accumulation and gas injection time at which the well can produce at its maximum capacity. This interdependence is plotted on a separate graph with the given times on two axis. This curve represents the values at which the reservoir inflow is maximised and hence another curve representing the tubing outflow is drawn on the same graph to intersect the former curve at the optimum value of liquid accumulation and gas injection time. The paper also discusses the physical significance of the cases in which the two curves do not intersect and its possible solutions which vary in accordance with the experience of engineers and conditions of well. Our mathematical calculation led to an astonishing result that the interdependence between the two given durations is elegant and can be easily found without the use of computer in a very short interval of time. The result indicated that if a tangent is drawn from a point representing gas injection time to the graph of accumulation height versus time, it touches the graph at the value of liquid accumulation time at which the production of well is maximized. This novel approach to determine the value of time in an intermitter or time cycle controller in an intermittent well can be proved to be a boon for gas lift optimizers who would otherwise spend a large part of the time in setting the value on hit and trial basis. The graphical method can determine the optimum value in a shorter interval of time and with greater accuracy saving companies from extra man-hours and unscientific approach to optimizing any intermittent gas lift well.
Hydraulic fracturing can establish well productivity in tight and unconventional reservoirs, accelerate production in low- to-medium permeability wells and revamp production in mature wells. However, not all wells are suitable candidates for hydraulic fracturing and the technique can be detrimental if the right candidate is not chosen. An integrated approach is required to select the wells that are the most-suitable candidates for hydraulic fracturing. This paper discusses the hydraulic fracturing candidate selection workflow and execution carried out in the year 2015 to 2016, which has unlocked reservoir production potential of Upper Assam basin fields of Oil India Ltd. (OIL). Wells which showed poor/no inflow prior to hydraulic fracturing operations, exceeded operator expectations during post fracturing production. Better reservoir management through hydraulic fracturing, rejuvenated ceased wells with an incremental oil production rates of 1380 bopd cumulative rate from six wells, post fracturing. The candidate analysis workflow described in this paper, can serve as the best practices guide for any operator investigating workover candidates among multiple fields, with an objective of production enhancement. A customized candidate selection methodology was developed to identify the 10 best candidates from a pool of 70 vertical/deviated wells in two phases of the hydraulic fracturing campaign. In the absence of dynamic reservoir analysis, offset well data analysis assisted in filling the data gaps by enabling geological and reservoir level understanding. Well production models were calibrated with the production history, geo-mechanical models were prepared and used in the fracture modelling to generate optimum fracture geometry and predict post-fracturing production. Wells were ranked according to incremental hydrocarbon production coupled with risk factors including completions integrity. In the execution, fracturing model was validated by performing fracturing diagnostics tests such as Step Rate and Minifrac injection. The final calibrated model was then used to design the optimum fracturing treatment. Given the age of wells and traditional completions architecture, best practices were developed to counter challenges of high pressures and rate limitations in wells with depth greater than 3500 m. As stimulations and well preparation in completed wells are expensive, it was critical to identify the most-suitable candidates with the available dataset before attempting well preparation and further acquisition. This was addressed through a customized workflow to perform production rate transient analysis for reservoir dynamic flow properties, create synthetic geomechanical models for stress profile & fracture vertical growth estimation.
Cased hole gravel pack (CHGP) is the most popular method for controlling production of formation sand in oil or gas cased hole wells. CHGP involves the packing of screen and casing annulus, and perforations to inhibit production of formation sand. Success of a CHGP depends on various factors such as perforation packing, cleanliness of completion brine, perforation strategy and minimizing drawdown. Quality of perforation packing aids in minimizing drawdown of gravel pack completions. This led to popularization of high-rate water packs (HRWPs), an evolved sand control method for cased hole wells. HRWPs involve pumping above fracture extension rate and placing gravels outside casing into the critical matrix. This paper discusses maturation process in design, execution, and evaluation methodology devised from a campaign of 16 HRWPs, which included two formation breakdown acid injections, one slim hole completion, two re-stresses and one top-off. Naharkatiya fields of Oil India Limited, in Assam-Arakan basin are characterized with high degrees of unconsolidated formation sand. Elements of heterogeneity like formation sand ingression rate, PSD, mineralogy and well-profile in these two fields, where most of the HRWP treatments were executed, demanded case-specific pre-gravel-pack workover operations. Installation of screens and pumping of HRWP treatment presented many challenges, such as formation sand ingression, high circulation pressures, uneven slack/pull weights and issues in tool operations. All these challenges were tackled in unique ways and successful HRWP treatments were completed. A holistic approach was developed towards execution of a High Rate Water Pack treatment, by analyzing all interlinked elements such as perforations, cores, cement bond, reservoir saturation, water cut and offset well history. Post-treatment evaluation of HRWPs using bottomhole gauges identified a sequence of downhole events and potential issues during execution phase. Correlating each new HRWP candidate with learnings from previous ones allowed the operator to better plan workover steps towards execution of the sand control treatment. Contingency plans were devised to tackle issues learned from previous wells, and many were successfully tested in the campaign. Production rates and choke strategies were optimized by analysis of offset wells. This paper presents data analysis of wells while correlating with their offsets. Post-treatment analysis has been discussed and correlations between suspected issues during execution with signatures in bottom-hole gauge data have been presented. Recommendation are further provided for drilling and completion operations. Evolution in design and execution process for case wells has been presented, which can be used as a reference literature for designing case specific sand control treatment program.
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