"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.
A major cause of increase in the number of well abandonments in small heterogenous formations with high geological complexities is early water breakthrough into completions which leaves pockets of bypassed oil that ultimately affects the overall recovery from such formations. This paper highlights some reservoir management strategies adopted to improve reserves from a Niger Delta formation with an API of 22 Deg. Reservoir management strategies adopted included the use of down hole gauges, inflow control devices, and detailed production/injection surveillance. Updated 3D simulation model and material balance analysis were also used for evaluation of waterflood recovery efficiency and real time Reservoir management decisions. Other Reservoir management practice helped in stimulating gas cap expansion that increased daily oil rate from this reservoir and field gas rate that helped in gas lifting wells in other heavy oil reservoirs with high BSW.
The use of inflow control devices (ICD) have been used to balance flux around wellbores and also delay breakthrough of unwanted fluid into completions.1-2. Inflow-control devices (ICDs) were developed to avoid coning problems in long horizontal wells. The model for the ICD consists of pressure-drop equations from the reservoir, through the screen, the flow conduit, the ICD nozzle, and into the production tubing, along with pressure drop through the lower-completion system.1-2. This technology has been a common practice in the petroleum industry for many years now. This procedure though has been beneficial especially in highly heterogenous small formations, but however causes some pressure drop which does not contribute to additional fluid inflow into the wellbore and this is seen to be an impairment to the productivity of horizontal wells to some extent. In wells that are equipped with ICD, a precise quantification of this additional pressure drop is of paramount importance to completely identify the existence of damage created around the well bore. Many authors have proposed mathematical solutions that can be used to estimate various pseudoskin factor caused by damage, partial completion, slanted well and perforation. No author has researched about productivity loss or skin that may result from the use of inflow control devices. In this work, a 3D numerical model which includes inflow control devices along horizontal wells was used to investigate reservoir and production performances of various ICD nozzle sizes. Different productivity losses from different nozzle sizes were seen as skin. Consequently, a simple equation for calculating this skin due to restricted fluid entry through ICD nozzles was derived. The skin results obtained from this new equation is compared with the result obtained using existing skin equation and the variance is within acceptable limit.
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.
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