Abstract
The everlasting emphasis on abiding by the forecasted plans and targets in Greater Birba while limiting operating expenditure exhaustion has paved the way for additional analysis and monitoring of current well performance trends in complex reservoir configurations such as Al Noor. Buried at deep depths underneath a high-pressure overburden, the Ara Salt depositional features in the southern basin of Oman present unique yet extremely challenging characteristics with respect to hydrocarbon extraction and subsequent production. Situated below the four primary carbonate layers of A1C-A4C, Al Noor Field's Athel-type formation poses one of the most challenging reservoir configurations across the region. Recent efforts to sustain free-flowing production in this field were initiated through applying the cyclic huff and puff process to spark the necessary pressure difference between the tubing head and the flowline pressures, allowing the well to remain active.
With projected additional constraints bound to augment the producing capacity, efforts to sustain a high yield from what remains to be a considerable extent of unrecovered hydrocarbons has called for a more thorough case study; one that is aimed at maximizing the capital gain as well as minimizing the environmental footprint and existing time constrains on the field operators.
The goal of this work is to present a thorough study of Al Noor field's huff and puff plan as well as highlight underlying subsurface and surface issues. Based on initial deductions, the task is to then analyze a wide selection of parameters on PI and energy component, both of which are primary production programming interfaces that are consulted to correlate existent depressurization patterns with respect to the tubing head pressure (THP) before and after kick-off procedures, lowest flowline pressure (FLP) readings, average choke opening sizes in order to contrive an updated categorization of the field's active or temporarily closed/quit wells; one based on the tested net production rate of each well against the duration of its quitting cycle in days/month.
Consequently, preliminary observations of a few wells unravelled startling revelations in terms of the potential for prolonging time elapse until quit. In addition to minimizing the operator's load and reducing quantities of gas flared, large capital gains were generated in proportion to the feasibility of reducing inefficient disparities, some even stretching to an excess of a $142,000 in relatively low producers and over a considerably small batch of tested wells. Following that, an implementation proposal comprised of a case-by-case strategy for three selected wells was relayed to the on-site operations team. The selection process was based on their optimization viability with regards to examined parameters as well as their productivity profile.
Instructions included following the standard procedure in ALNR 21 but depressurizing the FLP to below 4 bars instead of 40, aiming therein to maximize the THP after kick-off and stretch out the cycle. The choke size was adjusted from 50% to 20% opening in ALNR 20 to observe effects on rates as well as pressure maintenance and last but not least, apply the innovative pressure build-up theory in a quantitatively low producing ALNR 24. The effects of this strategy presented an overwhelming degree of success in augmenting post kick THP levels, steadying production rates and perpetuate the wells’ activity. Finally, case study focussed and general recommendations were outlaid for short to long-term future performance improvements.
Prediction of Missing Tubing Head Pressure Using Recurrent Neural Network