"Marginal field" was introduced to the oil and gas industry to identify those fields that have negative economic effects in its development. More specifically it is possible to define a marginal field as a field that is cost ineffective to develop with conventional oil and gas means of technology. Economic development of marginal fields in most cases requires the use of existing processes to minimize cost of finding evolving technologies in development of reserves. This paper generally evaluates the feasibility of using the enhanced oil recovery technique to improve reserves in a marginal field operation environment. A marginal heavy oil field in the offshore environment of the Niger Delta region which started production in 2011 is used as a case study to evaluate the feasibility of the use of enhanced oil recovery method to improve recovery. Due to poor mobility ratio in this heavy oil field and its associated big aquifer sizes, pockets of unrecovered oil have been left behind the water fronts and water cut has risen above 80% in most of the producing wells. Recent integrated field evaluation shows that the recovery factor is poor compared to the size of oil originally in place and this triggered the need to process subsurface assessments of developing such reserves that exist in any marginal field using enhanced oil recovery technique. This paper therefore goes through the fundamental scope of an enhanced oil recovery study process to determine the applicability of this technology in a marginal oil field.
An evaluation of potential EOR processes applicable in the marginal oil field operation of the Niger Delta region is presented. Technical feasibility, process availability, oil recovery potential, and other uncertainties and risks associated with exploitation of enhanced oil recovery technique in a marginal oil field environment are being assessed. Few Enhanced oil recovery processes, namely polymer flooding, chemical flooding and microbial EOR (MEOR), are considered for possible application in this marginal oil field. The objective of the screening study is to evaluate and rank the EOR options and also select the most attractive method that will have to be further chased to a pilot test stage. Emphasis is strictly on a technical assessment of the incremental oil potential of each of the EOR methods and also identification of critical operational and logistical components of the entire process for their implementation in the offshore operating environment. Recoverable volumes associated with EOR may be significant, but key project development and implementation challenges and extra cost elements must be considered in any EOR forecast for an effective EOR process ranking. Some of these concerns (e.g. Polymer/chemical supply, facilities requirements, and the impact of EOR on reservoir performance and wellbore integrity) may be significant enough to eliminate a method from being considered further and at that point the best EOR option that requires minimal cost exposure for achieving the best recoverable shall be considered. Moreso, there is consideration of the quantity and quality of laboratory data that should support the viability of each EOR process being considered. This paper narrates the state of technical readiness for field implementation of each EOR method and identifies remaining work required to progress EOR process in this marginal oil field.
Wax precipitation along oil well tubing causes deferment in production while being produced from the formation through production facilities. Existing formulations for inhibiting wax formation include, chemical injection at different dosages and depths, mechanical inhibiting forms and thermal methods used in overcoming wax formation temperature. A well in one of the Niger Delta offshore field suffered down hole wax deposition after each field shut down. A triplex pump which serves six fields was used to provide a remedial solution after an average well downtime of seven days. In order to control this challenge, crude oil pour point was determined from historical production and temperature profiles and a hot reservoir fluid circulation strategy was developed with the objective of optimizing production through reduced well downtime and minimized expenditures. The technique used shall be discussed in this work. This formulated strategy saved over a five million US dollar per annum.
Optimizing oil production with facility constraints has become a challenge to most E&P companies even as they pursue sustainable resources. The innovative gas lift technique overcomes this challenge. The conventional gas lift well system has long been in use, but the design most times is limited by gas availability and pressure which limits the depth of gas lift injection for improved production rates. This challenge may not be evident in matured producing fields with gas compressors installed with available non-associated gas source wells, but truly such challenges arise in new fields especially owned by indigenous companies where much uncertainties at an early field life unavoidably allows you to be more stringent in expenditures towards development of a field gas lift project. A new gas lift concept was developed and studied in Field A in an offshore field of the Niger delta in the absence of gas compressors. This design has been proven to be suitable because it was used to bring four closed wells online even when those wells were removed from the company annual forecast. The original design consists of a minimum of two unloading valves and an orifice at a deeper depth, but because of the absence of scrubbers and gas compressors in the facility, pressure depletion in the reservoirs caused four flowing wells to be closed. The new design then sets dummy at shallow mandrels and uses a modified size of orifice to optimize available pressure and gas required to open the closed wells and still sustain other gas lifted wells connected to the same gas lift manifold. This campaign resulted to an additional 7000Bopd which is the primary discussion of this paper.
The field under consideration is located about 50 Km offshore Nigeria in water depth of about 130ft. The field was discovered in 1968 with X1 well. This particular well encountered oil in four different zones (IX, X, XI and XII) in the Pliocene Agbada formation. The X1 well was logged and tested to evaluate the potential. The second well, X2 was drilled in the early 70s and that was in a separate fault block. This second well encountered oil in two reservoirs, IX and X. The XI was poorly developed in X2 well relative to X1 well which was found wet. The XII reservoir was encountered with good oil shows and gas readings were found in poorer sections of the reservoir. A third well was drilled which did not encounter any hydrocarbon and many of the sands were poorly developed or absent relative to the X1 and X2 wells. No testing was conducted in this well. The field was appraised with X4 well. The X4 well encountered oil in all the four sands. Pressure and log data were taken from the reservoirs in this well and the well was tested to know the true potential of each. The reservoir sands are of good to excellent quality but are unconsolidated and sand control will be required in the development phase. The fluid quality is 25 deg API with moderate viscosity and a moderate GOR in the XII, and about 14 deg API with high viscosity and low GOR in the other reservoirs. Reservoir pressure and temperature is normal in the IX sand, slightly over-pressured in the X sand and significantly over-pressured in the XII. Following the successful results of the subsequent appraisal programme, the reserves level increased significantly to more than 40 MMbbls. At this level the field was judged large enough to support a stand alone development. This had allowed a first proposal to initiate an initial development plan for the Field. Development drilling commenced in 2009 with first oil was recorded in 2010. As the development of the field progressed the lessons learnt from first development phase of drilling were implemented in the second phase. This led to better wells with improved production rates. In addition, effective reservoir management in the field has led to optimized production which saw recovery factor in these oil rim reservoirs getting above 30%. This paper highlights the challenges encountered, innovative solutions and key learnings along each phase of development.
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