Enhanced oil recovery has been gaining relevance over the years following success stories from already executed projects from various parts of the globe. The recoveries from such successful projects have tremendously increased the terminal life cycle recoveries from the subject reservoirs and subsequently the project Net Present Value and Value to Investment Ratio. More than 90% of Field Development Plans in the Niger Delta have not considered Enhanced Recovery Mechanism as part of the field development options and as such Top Quartile Recovery Factors are never achieved. In this study, the effectiveness of Enhanced Oil Recovery within the Niger-Delta reservoir sands via 3-Dimentional Dynamic Simulation, Economic models and Experimental investigations (temperature and pressure effects on polymer effectiveness) was done. The GN7000 reservoir was used as a case study for this work. This reservoir is the largest gas cap reservoir in the N-Onshore field within the Niger Delta area and it is at the mid-life stage. This study tested the effectiveness of three Recovery mechanisms (Water Flood, Polymer Flood and Polymer Alternating Gas). Simulated and Experimental result suggests that Polymer flooding and Polymer Alternating Gas (PAG) yields greater Technical Ultimate Recovery, better economic indices but greater complexity in polymer selection due to inherent high reservoir temperature and low salinity that make the use of synthetic polymers inadequate. Experimental investigation showed that biopolymers are most suitable for this sand. The suitability of some biopolymers (Xanthan and copolymers containing high level of 2-acrylamido2-methyl propane sulfonate (AMPS) showed good results. Study results shows that with the deployment of biopolymers with high viscosifying power and high resistance to thermal degradation an incremental recovery of 8% from the natural flow could be achieved. Research findings indicate that biopolymers could yield good results for Niger Delta sands within the pressure and temperature ranges of 93°C and 290 Bar.

Champion is a multi-billion bbl STOIIP oilfield offshore Brunei. It is a mature field with over 250 producing wells. Oil production commenced in 1972, and production to date is less than 20% of the oil initially in place. The feasibility of increasing recovery through a major waterflooding programme is currently under evaluation. Potential incremental oil recovery is 8%. Significant capital investment (up to 140 new wells and 10 new jackets) will be required to realise this opportunity. It is, therefore, important to capture the full range of possible subsurface scenarios early in the study. A fundamental first step in the integrated modelling workflow has been to develop an understanding of the depositional and tectonic history of the field in order to create static models that capture the range of uncertainty in geometry and properties of the reservoirs. Data from core, well logs, seismic and outcrop analogues have been integrated to produce depositional models, highlighting uncertainties in reservoir architecture as they would impact potential waterflood recovery. Two broad types of reservoir interval have been recognised:stacked shoreface parasequences, which form the majority of Champion reservoirs. In general, these comprise a gradational succession from basal offshore-transition zone heterolithics to amalgamated low angle cross-stratified sandstones of the lower shoreface zone. Correctly considering stacking patterns and degree of vertical connectivity between sands is important to the success of a waterflood.tidally-dominated sediments, comprising tidal channel fill or bar complexes set in a background of mud to sand-dominated tidal flat facies have been recognised. For these sediments, channel sand geometry, orientation and internal permeability anisotropy are crucial to predicting fluid flow. The results of the sedimentological review have been used to create a series of 2D cross sectional dynamic simulation models, covering the range of depositional environments, and a range of connectivity scenarios. The main conclusion of this study is that water is the preferred injection fluid for all of the Champion field reservoir intervals studied. Water typically gives a 15–20% (absolute) higher oil recovery factor than gas. The impact of the sedimentology review and modelling is that it will enable early selection of water as the injection fluid. This means that surface engineering work can focus on water injection scenarios, reducing the time required to identify a preferred development plan and accelerating project implementation. Introduction The Champion field has been producing oil since 1972, with current production of less than 20% of the STOIIP. Reserves replacements from infill drilling are becoming increasingly difficult to find, so a new approach was called for. In 1997, development focus was on "halting the decline in production by locating and exploiting remaining undeveloped reserves using primary depletion, rather than economically marginal secondary recovery methods" [1]. Since then, oil prices have risen from US$23 to US$50+ per barrel (average annual US crude oil prices, inflation adjusted, data source: www.inflationdata.com), and a major secondary recovery project, with economies of scale applied to the whole field instead of isolated reservoirs, now becomes attractive. A scouting study, carried out in 2004, has identified that Champion field could produce an additional 8% of the STOIIP over a period of 28 years, if a major secondary recovery project could be put in place. The scouting study indicated that the scale of investment under consideration could be up to 140 new wells, 10 new well jackets and associated pipelines, and injection facilities. One of the major recommendations of the scouting study was that the traditional piecemeal approach to the development of Champion should be abandoned in favour of a more holistic apporoach. To this end, the three separate field teams previously responsible for the field development were merged, and a new integrated team structure put in place, with over 30 staff, comprising subsurface and surface.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPetroleum resources represent a significant part of a company's upstream assets and are the foundation of its current and future upstream activities. Often times, at the discovery of a new field or extension of an existing field, there are uncertainties associated with quantifying the amount of hydrocarbons in place. These uncertainties may be related to the structure, aerial extent of the accumulation, unseen fluid contacts to delineate the vertical extent, internal architecture of the reservoir and the characteristics of the resident fluid(s). In some cases, companies may complete and produce discovery wells before they can fully appraise the structure or may be forced by other considerations such as community disturbances to abandon appraisal drilling and continue to produce from existing well(s). All these and much more, have an impact on the evaluation of in-place hydrocarbon resources and consequently recoverable hydrocarbons. In Field Development Planning, it is routine to identify and quantify the impact of major subsurface uncertainties such as the in-place volumes and their distribution. This paper presents the methodology and results of an integrated disciplinary effort at translating uncertainties into a range of static (in-place) volumes for the purpose of field development. Erratic sand development, paucity of biostratigraphic control coupled with a complex structure make the G1.0 complex of the EGBM field one of the least understood hydrocarbon reservoirs of the Northern depobelt -Onshore, Niger Delta, Nigeria. Lack of PVT samples and analyses also add to the uncertainty in fluid properties. The erratic distribution of the petrophysical parameters especially from the G sand core also contributes to the petrophysical uncertainties.The construction of 3-D static reservoir models based on the understanding of facies and their relationships, through the integration of all available data have been used to enhance the understanding and quantification of the uncertainties. Standard evaluation of uncertainties in the spread of petrophysical parameters like porosity, hydrocarbon saturation and Net-to-Gross ratio was carried out and compared with the multiscenario concepts incorporated in the geological models. PVT parameters were derived for the reservoir based on analogy and correlations constrained with production and test data. Efforts were also made to comply with definitions of proved reserves by Securities and Exchange Commission (SEC) while still evaluating expectation volumes for internal purposes. An attempt has also been made in comparing results from the probabilistic volumetric evaluation of this reservoir and the deterministic (best estimate) method.

This work demonstrates the usefulness of data quality checks for the purpose of achieving test objectives with an example from a Niger Delta well. The well UGO-1X was completed as single-zone single string (SSS) configuration with a 4-1/2 inch, 12.75 ppf, 13Cr HCS production tubing. The well was tested in order to characterize the reservoir, determine the completion efficiency and ascertain reservoir limit for GIIP estimation. The test program involved multirate production, followed by a build-up phase for which a Down-Hole-Shut-In-Tool (DHSIT) was deployed to manage wellbore storage effects. However with the conclusion of the multirate test, and commencement of build up, the downhole shut in tool (DHSIT) failed and subsequently the well was shut-in at the surface and the build up (BU) stage allowed to progress as per programme.Following the conclusion of UGO-1X multi-rate test (MRT drawdown and build up), the data was retrieved from the quartz gauges, quality checked and analysed using the conventional and numerical simulation methods. This paper illustrates the difficulty of interpreting an incomplete set of data, the importance of properly understanding the operational history in well test analysis as well as the usefulness of conducting a quick analysis to validate data thereby avoiding a repeat operation. It is shown that by careful reprocessing of the data (de-listing data within the DHSIT failure interval), the overall quality of the data could be significantly improved and used to produce credible results. This made it unnecessary to conduct a repeat of the MRT/BU on UGO-1X as initial test objectives were achieved.

The M001 project involved the hook-up of 12 wells (17 conduits) which were drilled and completed between year 2000 and 2005 but were closed-in for operational reasons, until year 2019 when the first seven (7) conduits on cluster MX1 were cleaned up successfully. The seven conduits (Well-A, Well-B, Well-C, Well-D, Well-E, Well-F & Well-G) were expected to flow via three 8" bulk lines. Post well open-up and handover to production, significant bulking / backing out effects were observed. An average Flow Line Pressure (FLP) of ∼22 bar was recorded on the flowlines, hence limiting the capacity to bulk the wells, [FLP increases towards Flowing Tubing Head Pressure (FTHP) hence, pushing the well out of the critical flow envelope as FTHP<<1.7FLP]. Due to this challenge, total production from Cluster MX1 was sub-optimal with only five (5) conduits out of seven (7) able to flow due to bulking and backing out effect. The sub-optimal performance from the conduits were investigated using the Integrated Production System Model (IPSM) / PIPESIM models. Four different scenarios were run in the model and the calibrated IPSM model indicated all 7 conduits should flow if there are no surface restrictions. The model identified pressure, mass and rate imbalances in the integrated system and suggested the presence of a restriction at the manifold, causing sub-optimal production from the wells. The model outcome triggered an onsite investigation / troubleshooting from the wellhead to the manifold at the facilities end where an adjustable choke was identified in the ligaments of the manifold. In line with process safety requirements, a risk assessment was carried out and a Management of Change (MOC) raised to remove the adjustable choke at the manifold. Post implementation of the intervention, all the seven (7) conduits produced without any bulking effect. Total production realized from the seven (7) conduits post execution of the recommended action is ca. 9.3 kbopd against 5.2 kbopd pre-intervention. A total of ca. 4.1 kbopd production gain was realized and 10 mln USD proposed for additional bulkline was saved.