The Mangala field in the state of Rajasthan of western India was the first major oil discovery in the Barmer basin and is the largest discovered oil field in the basin. It contains paraffinic oil with average viscosity of~15 cp and wax appearance temperature only about 5°C lower than reservoir temperature of 65°C. The initial development plan was a hot waterflood to prevent any in situ wax deposition; recently, though chemical EOR methods have started to play an important role in the development of the field.A polymer flood pilot was successfully conducted in the field. It was followed by an ASP pilot trial which used the same set of wells. Unlike the polymer pilot, ASP injection was confined to a single continuous sand to reduce interference with nearby wells and to reduce the uncertainty in interpretation of pilot results. A combination of a high molecular weight branched alcohol PO-EO sulfate and a high carbon number sulfonate was selected for the ASP formulation. The selected surfactants functioned well in the desired salinity range and were stable in an aqueous solution up to half a percent higher alkali concentration than the optimal concentration.The pilot facilities needed to meet a number of challenges arising from using neat surfactants-mainly handling of viscous/gelling material, maintaining accurate dosing rates, maintaining the right ratio of two surfactants, and maintaining stability of the sulfate itself. These challenges were surmounted in the pilot by using a blended surfactant solution, diluted with water, with activity of 24%.ASP injection led to mobilization of significant volume of oil in the confined 5-spot pattern. The oil-cut of the central producer increased from 10% to 80%. The oil production rate showed almost an eight fold increase from 50 bopd to nearly 400 bopd. The estimated incremental recovery over polymer flooding is nearly 20% of the pilot STOIIP. Later in the pilot project the expected increase in water-cut was accompanied with the production of the injected chemicals along with rise in the pH of the produced water, indicating that favourable mobility was maintained during ASP injection. Some production challenges were encountered-most notably the failure of the producer's electrical submersible pump (ESP); this required the producer to be put on jet pump intermittently when the ESP was not functioning. The saturation observation wells located within the pattern area showed significant desaturation of oil. Sponge cores acquired after the pilot showed very low remaining oil saturation in the flooded sections. The paper will discuss the pilot operations, monitoring and quality control, the pilot results, and lessons learnt.
SPE/IADC Members Abstract The evolution of well designs that has taken place in Prudhoe Bay Unit (PBU) is described in this paper. The reasons for the differing well-types are explained, emphasizing how the completion profiles & designs are tailored for the particular reservoir offtake plan at the target location. The central driver of the evolving designs is always to retain development drilling as an attractive investment in an environment of a decreasing trend in incremental reserves recovered by new wells. The major conclusion to be drawn from the review, is that to continue with a profitable development drilling program, the PBU operators have moved away from the simple 'off-the-shelf' PBU well designs of only a few years ago. The various drilling & completion methods employed today, recognize the value of the existing infrastructure available and the differing production opportunities and problems that are present in the PBU reservoir. The goal of the reservoir development drilling program is a sophisticated balance between minimizing development costs, while providing a quality completion that optimizes production rates, allows future well-work options, and provides appropriate well longevity. Introduction Prudhoe Bay Unit is currently undergoing the most active development drilling program in its twenty year production history. Over 100 reservoir penetrations have been achieved in the past year, with a similar rate of activity planned over the near-term future. This program is occurring despite the number of wells originally envisaged having been greatly exceeded and the field now being well into it's decline phase. The Prudhoe Bay field was discovered in 1968. Original oil-in-place is estimated at 22 billion barrels, with ultimately recoverable oil reserves projected at around 13 billion barrels. To-date over 9 billion barrels has been produced. There has been an ongoing development drilling program since the mid-seventies. First production occurred in 1977, with a plateau production rate of 1.5 MMSTB/D being attained by end 1979 and lasting until 1988. The field has now been in decline eight years. Many incremental development projects are being undertaken in order to mitigate the production decline, and new reservoir penetrations are a key element of many of these projects. As field-life has matured, the distribution of gas, oil and water in the reservoir has become far more complex and target locations have become smaller. Consequently drilling & completion practices have had to evolve to meet new challenges in order to keep development costs at an economically attractive level. Unit development work is normally carried out in multi-company, multi-disciplinary teams. This practice has encouraged innovative well designs and reservoir access methods. The main drilling & completion options currently available and utilized in different circumstances in PBU include: new wells vs. sidetracks; rig-type: conventional rotary vs. coil tubing drilling unit; completion profile: horizontal/high-angle vs. conventional; directional build profiles: short vs. medium radius; Liner type: slotted vs. solid & selectively perforated; completion tubing metallurgy: chrome vs. carbon-steel: New and developing options still in their infancy in PBU include, thru-tubing rotary drilling (TTRD) and multi-lateral well designs. The field's history and that of it's development drilling program may be characterized into three distinct phases:discovery to plateau production;plateau production; andproduction decline. Each segment required differing engineering emphasis. In the long post-plateau phase of PBU's drilling history, the key is, and will remain, that of cost effective incremental development by pursuing innovative techniques to access the field's remaining reserves. P. 323^
Bhagyam is a large oil field in the Barmer Basin of Rajasthan, India. The major producing intervals are shallow Paleocene-aged Fatehgarh sandstones. The paraffinic oil is viscous (20-500 cP) with wax appearance temperature (WAT) only 2-3°C lower than the average reservoir temperature of ~53°C. Bhagyam has been developed with 153 wells in an edge linedrive waterflood and has been producing since 2012. However, performance has been less than projected in the initial field development plan (FDP): not as good as the nearby Mangala and Aishwariya Fatehgarh waterfloods and at the lower-end of that seen in worldwide viscous oil waterflood analogues. Key contributors to Bhagyam's performance were lower than expected initial well productivity and a more rapid rise in water cut than projected. The lower initial well productivities were surprising when compared with experience from Mangala, where initial well productivity was closely aligned with expectations. Simulation models could not replicate Bhagyam performance without numerous major local modifications; hence long-term model predictions were not sufficiently reliable for business planning. Reservoir behaviour was initially attributed to severe heterogeneity and early models used high permeability streaks to match performance. However, saturation logs and selective zonal flow back of a few wells showed that injected water was not confined to select high permeability streaks but was widespread both areally and vertically. The more diffuse nature of water movement suggested a fundamental disconnect between field dynamics and the simulation model description and physics.
Summary The Bhagyam field contains medium-gravity viscous crude oil. Notably, its waterflood performance has been substantially worse than projected in its initial field development plan (FDP) and poorer than in nearby analog fields and other viscous oil waterfloods from around the world. Early simulation models could not replicate Bhagyam waterflood performance without numerous major modifications. Poor performance was initially attributed to unforeseen severe heterogeneity. As data accumulated, conceptual simulations showed that an extreme level of heterogeneity was required to match observed performance, suggesting permeability heterogeneity alone could not explain results. Log data from later infill wells also showed that injected water was not confined to high-permeability streaks but was areally and vertically widespread. Two major changes drove significant improvements in waterflood simulation history matches. First, a new porosity/permeability model calibrated to pressure falloff (PFO) tests in the aquifer resulted in a higher degree of heterogeneity, which accelerated water production in updated simulation models. Second, a new oil/water relative permeability model that accounted for the hypothesized presence of a small, solid wax saturation reduced initial oil relative permeability and predicted oil rates, and further accelerated water production. Resulting simulation models showed excellent history matches and have continued to match performance during the past 2 years with only minor additional modifications.
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