This paper presents a cost analysis / comparative study of the return on investment realized from the downhole chemical treatment of the Coora CO365 well. The technologies available to permanently outfit older wells that are completed with sub-surface safety valves (SSSVs), with the ability to benefit from direct down-hole chemical remediation, are also detailed. Producing from a field that was first developed in 1936 and located in southern Trinidad, Coora CO365 experienced paraffin deposition in the near-wellbore and along the well's production string early in its productive life. The operator followed long-term strategic workover plans, but paraffin deposition still continued. Further investigation highlighted that the implementation of an optimal chemical injection program would be critical to realize maximum financial benefit from production of this maturing reservoir. The operator has been able to replace high-cost workovers with low-cost chemical treatment, significantly improving the economics and prolonging the productive life of this well. Through comparison with older wells (in this block), completed without direct downhole means of chemical remediation, this case will show that simple modifications, though incurring upfront capital cost, can result in long-term revenue generation and early payback, if combined with an appropriate chemical remediation package. The analysis will dispel the common misconception that the cost incurred in refitting older wells with downhole injection capabilities overshadows their revenue generation prospects. In many cases, the natural decline of a field can be exacerbated by flow-assurance issues in wells and equipment. This paper highlights the potential to sustain production in brownfields that have been plagued with these issues via the use of downhole chemical injection.
The remediation of flow assurance challenges in field's offshore Trinidad is a foci of oil and gas operators in Trinidad West Indies. These challenges are heightened by field maturity and the corresponding increase in water production. With this increased water influx, production chemistry and specific flow assurance challenges also arise. One of the primary challenges include the precipitation and deposition of inorganic mineral scales. Coupled with this, mineralogy data and core data studies indicated that the sands of some of the producing fields offshore Trinidad are highly susceptible to scale precipitation in the formation water (Holder, 1990). As such, measures are often implemented to assure the successful and economical flow of hydrocarbon stream from the reservoir to the point of sale. In this geographical area, stimulation acid treatments were typically deployed for remediation of formation damage of which scale precipitation was a main type. However, based on the previous production histories, the production gains following these acid treatments were short-lived. In addition, the accompanying financial loss is often compounded by other flow assurance challenges that were precursed by scale deposition. This paper will discuss the use of inhibitory squeeze application techniques as a preventative approach to formation damage resulting from scale precipitation. This application is the first of its kind performed in the Teak field. Thus, results obtained will highlight further opportunity to successfully stimulate other fields in this region prone to scale deposition. The results obtained from this application will be represented in the form of a comparative analysis. The production indices attained via the conventional means of scale remediation, will be compared with that achieved via the strategic placement of phosphonate-based chemistries. Additionally, methods employed to avert the challenges of squeeze treatments in offshore environments will also be discussed as well as lessons learned from this approach.
Paraffin deposition in production tubing and flow lines is a phenomenon that affects many oil producers. Once paraffin wax has precipitated there is a tendency to agglomerate peripherally to the production flow path which eventually leads to a sectional decrease in tubing or, even, flow blockage across production zones. The impact of paraffin deposition ranges from wellbore issues, flow assurance challenges to total production impairment. In many mature fields, paraffin remediation can be challenging when deposition occurs in the formation especially in near-wellbore regions of producing wells. Temperature loss at these locations induces wax crystallization and subsequent formation damage. A mitigative approach to paraffin deposition in these areas can typically include the utilization of both paraffin inhibitors and paraffin solvents individually or in combination. However, as it pertains to paraffin remediation downhole, inhibitor placement in the formation or at near-wellbore has proven to be very challenging. This paper reviews the performance of two main chemical applications applied to address downhole wax deposition in a well from a South West Trinidad oilfield. The paper also discusses the strategy behind identifying the chemical type for the application and considerations for the placement of the chemical treatment to impact its intended target based on well data and well infrastructure.
Maturation of hydrocarbon reserves often occurs conjointly with an increase in flow assurance challenges. Deposition of paraffin and/or asphaltene is at the forefront of these challenges. Well maturity, declining reservoir pressure, coupled with hydrocarbon deposition, negatively impact the economic potential of a given reserve. Trinidad's Block Two Region is inundated with hundreds of mature paraffinic wells. To maintain cost effectiveness; proactive initiatives must be implemented with minimal operational expenditure. One such initiative used in the remediation of downhole hydrocarbon deposition, is the implementation of downhole treatment via chemical additives. Newer wells are often completed with allowances to enable targeted downhole chemical remediation. However, for older wells, as is the case in some Trinidad onshore blocks, the implementation of these enhanced modes of downhole chemical delivery, typically requires redesign of the downhole completion. The capital associated with this activity is considered cost prohibitive given the current oil price and low oil production from majority of these wells. This paper serves to highlight the profitability study with regards to the successful implementation of three common modes of topside treatment of paraffin deposition; steam treatment, annular chemical injection, and periodic batch treatment. It will also compare the return on investment associated with these successful applications. In this present economic climate, it is imperative for producers to adopt a proactive approach in the resolution of flow assurance challenges, namely hydrocarbon deposition, to ensure maximized production.
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