The relation between porosity, permeability and pore architecture in complex reservoir units, typical of the thin bedded canyon turbidite system within the clastic reservoir rocks is complicated and indistinct. The sedimentary architecture usually overprinted by late diagenesis results in the intrinsic complexities which pose major problems in modelling these systems. Detailed assessment of flow units is essential for a better understanding of the reservoir flow behavior and relation between storage and flow capacity. These units are zones composed of similar rock types that are in hydrodynamic communication, which possess stratigraphic continuity and have a strong relationship to pore geometries and rock type, but may not correspond exactly with the depositional facies.
This paper presents the application of the normalized pore throat radius (
Results of the analysis for the various genetic reservoir units demonstrate an improvement of 60% over existing methodologies with additional capability for delineating between zones with excellent high communicationand baffles. In addition, Correlation between the irreducible water saturation from mercury injection capillary pressures and FZI presents an improved efficacy of the
Iyowu, Chizoba (Shell Petroleum Development Company) | Chimere, Nwoji (Shell Petroleum Development Company) | Igben, Pius (Shell Petroleum Development Company) | Nwachukwu, Israel (Shell Petroleum Development Company) | Theophilus, Ugonwanne (Shell Petroleum Development Company)
Suspension Caps are used on wells that are temporarily suspended with plans that these wells could be reopened up for production in the future; or wells scheduled for permanent abandonment at a later date. Prevalently suspension caps have flanges that would fit into the tubing hanger equipped with a kerotest valve for taking pressures. These also have only a single bore covering two strings which makes it impossible to intervene on individual strings for dual string wells. To overcome these typical challenges, fit for purpose suspension flanges were designed with Gate valves that provide additional barriers in case the barriers on the wells are compromised. These suspension flanges are also designed with two bores for dual string wells making the ease of intervention on individual string possible.
Wells are designed and drilled with the intention of producing till the reservoir is appreciably depleted after which the well is finally abandoned and environment restored to its natural habitat. The expected total production from a typical well has however been impacted by the current trend of vandalism experienced in Nigeria especially in Niger delta. Most of SPDC wells are vandalized prior to the end of their life cycle and have exposed the company to various challenges such as exposures to environmental pollution, reputation issues, loss of Assets, etc. These challenges prompted the wellhead/well integrity team of SPDC to ingeniously design suspension caps that would improve ease of intervention on the wells without compromising any safety standards at lower cost and response time. The paper demonstrates the value in the use of these modified suspension caps especially in terms of safety and cost appreciation.
Decline Curve Analysis (DCA) is an important tool used in the petroleum industry to forecast future production performance. Forecasting future production performance is one of the critical inputs in the economic analysis of Oil and Gas investments. Conventional DCA (Arps' approach) has however been shown to have limited accuracy in forecasting cumulative production for solution – gas – drive reservoirs.
Fetkovich introduced a novel method of combining rate equation and material balance equation for finite systems to obtain rate – time equations for solution – gas – drive reservoirs, using the backpressure exponent (n) in place of the Arps' decline exponent (b). This work extends Fetkovich rate –time equation approach by developing cumulative – time and cumulative – rate models, for the two basic forms of the material balance equation investigated viz: PR is linear with Np (or Gp), PR2 is linear with NP (or Gp).
The models developed were validated with production data from two reservoirs, the first reservoir presented in the original Arps' paper and the second reservoir located in Niger Delta, Nigeria. The models were found to provide more accurate forecast of the cumulative production of a solution – gas – drive reservoir than the Arps' approach. The developed models also yielded results which compared favourably with the actual cumulative production data from the solution – gas – drive reservoir in Niger Delta. For the Niger Delta reservoir, the forecasted oil in place gives 128.844MMstb while the actual (estimated) oil in place was 127MMstb, a difference of 1.69%.
Agbami field is a deep-water field located offshore Nigeria. The oil production system is a complex intelligent production network that consists of 22 subsea production wells (19 wells are dual zone completion while 3 wells are single zone completion), 8 subsea manifolds, 8 infield subsea flowlines and 8 subsea flowlines/risers. A production network model for Agbami production network was built in GAP production modeling tool. The model consists of 41 inflow elements, 177 pipe elements, 68 chokes and 200 nodes with real-time pressure/temperature (P/T) measurements. Due to the large number of elements and P/T nodes in the model, it was very daunting to calibrate the model by unstructured manual tuning of the model calibration parameters. In fact, it takes several days to manually calibrate the whole production network. A structured computer assisted calibration workflow was developed to aid in fast calibration of the Agbami production model.
The structured approach to the Agbami production network model calibration used in this work is to first break down the model into 8 independent riser subsystems. Each riser subsystem is then further broken down into segments. The segments are zones, wells, infield flowlines, and flowlines/risers; with each segment having several elements and P/T nodes. Each segment of the model is independently calibrated using the latest production test data corresponding to that segment. A computer guided wizard was developed to sequentially match the P/T at different nodes of the segment using the Secant root-finding algorithm1. The calibrated segments are then coupled together into riser subsystems and each riser subsystem is then calibrated to the latest riser tests by manual adjustment of few parameters. The riser subsystems are further calibrated to the current conditions. The use of the structured computer assisted workflow has resulted in the faster model calibration time of within a day.
In Deep Water (DW) turbidite reservoirs in the Gulf of Guinea (GoG), waterflooding is deployed to maintain reservoir pressure and improve hydrocarbon recovery. The overall recovery from a reservoir under waterflooding is the product of displacement efficiency (DE), which is a function of remaining oil saturation (ROS) of the swept region, the vertical efficiency, and the pattern efficiency.
Analysis of open hole logs from recent infill wells in the Eko field that penetrated swept intervals provided useful insight into in-situ ROS values. The found ROS of between 0.05 to 0.11 were significantly lower than the 0.2 observed from core. The resulting DE of 87% estimated on the basis of the ROS data across these swept intervals has the potential to significantly improve economic robustness of some DW projects if proven correct.
Based on Welge's solution of the flow equation, a method (JBN technique) to calculate the individual phase relative permeabilities from displacement data was developed for the first time in 1959. It's the most commonly used data reduction method for obtaining relative permeability relationships from unsteady state data. Similar to the Welge method, differentiation of data is required and negligible capillary end effects are assumed when using the JBN method. To apply the JBN method, information on pore volumes of fluids injected and produced, the pressure drop across the porous medium and fluid viscosities is needed. This method generally gives relative permeabilities over a fairly small saturation range, which varies depending on the relative mobilities of the flowing fluids. In order to improve the results of this method, many researchers have come up with different techniques in their JBN analysis including the cubic spline numerical modeling technique (CSNMT) discussed in this research. This paper presents relative permeability data obtained from comparative analysis of the JBN method with different approaches. The differentials of second order Lagrange interpolating polynomial and cubic spline numerical modeling technique (CSNMT) were all considered in the JBN analysis. The relative permeability curves were then analyzed and the best method was chosen. The results of all the different methods employed in the JBN analysis do not match perfectly throughout the entire saturation range. The errors in the use of the differentials of second order Lagrange interpolating polynomial on more than three data point are very substantial. The results obtained from the application of cubic splines are more representative of the relative permeabilities from the field cores.
Fagbami, Debo (Xenergi Oilfield Services) | Echem, Chukwudi (Xenergi Oilfield Services) | Okoli, Amaechi (Xenergi Oilfield Services) | Mondanos, Michael (Silixa Limited) | Bain, Andy (Silixa Limited) | Carbonneau, Patrice (Silixa Limited) | Martey, Amarquaye (Midwestern Oil)
Nigeria is Africa's biggest crude producer but its revenue is severely reduced by theft and attacks on oil pipelines that significantly impacts crude production and fuel supply. Substantial efforts have taken place in collaboration with local communities, producers and oil operators to engage New Technologies in a bid to combat oil theft and pipeline sabotage.
Integrity monitoring of oil and gas pipeline pipelines can quickly identify a leak or third-party incursion event. Distributed optical fibre sensing offers a pipeline monitoring system that is not available with any other technology. Early detection of a leak or intrusion together with the accurate identification of the location allows time for either safe shutdown or rapid dispatch of security, assessment and clean-up personnel giving benefits in terms of reduced environmental impact and reduced helth risks to the local population. An effective and appropriately implemented monitoring system can easily pay for itself through reduced product loss, potential consequential losses and an increase in public confidence.
A Distributed surveillance system one of the first installed in Nigeria will be introduced. The System has been introduced to the Umugini pipeline, a crude oil evacuation route for four Nigerian marginal field producers in the western Niger Delta. The system uses the FALCON Platform developed by Xenergi. The system includes intrusion detection and leak detection based on both acoustic and temperature variations. At the heart of the system are both the Ultima™ Distributed Temperature Sensor (DTS) and Distributed Acoustic Sensor (intelligent DAS) allowing coverage of ranges up to 10's km continuously.
The project had to overcome a number of challenges, including the variable installation conditions imposed by the terrain & local climate, contractors unfamiliar with the technology and community concerns. Overcoming these issues gave a system that delivers 24/7 coverage of the Umigini pipeline from a single monitoring location giving the operator financial benefits in reduced product loss and more efficient deployment of resources.
The Silixa intelligent Pipeline Surveillance System (iPSS™) allows oil & gas pipeline operators to continuously and simultaneously monitor for leaks and threats to the pipeline along its entire length, and is the only system that can offer such complete coverage. Utilising fibre optics and underpinning the detection technology is Silixa's world leading Ultima &
Tunji, Bakare (The Shell Petroleum Development Company Nigeria Limited) | Waazor, Korubo (The Shell Petroleum Development Company Nigeria Limited) | Olugbenga, Daodu (The Shell Petroleum Development Company Nigeria Limited) | Suleiman, Ahmed (The Shell Petroleum Development Company Nigeria Limited) | Chima, Emelle (The Shell Petroleum Development Company Nigeria Limited)
Gas reservoir development at inception is often linked to detailed surface infrastructure development and long term contractual agreements with only a few appraisal wells. A thorough and detailed technical estimation of the size of the pie is an important step in the right direction. This is characterized by seismic acquisition and interpretation, scanty appraisal wells proving useful reservoir and fluids properties data and contact tagging. Calibration of regional properties with nearfield analogue can also be quite useful.
All these form the basis of the field/Reservoir development plan. For a gas development, the optimum development wells depend on a variety of factors identified at the field development stage often targeting the most viable crestal part of the reservoir for optimal development. Post drilling of development wells where reservoir static properties are fairly known and at the early stage of production when there is paucity of production data, it is imperative to adopt a robust approach to evaluate the technical UR.
In early producing life of the reservoir when reservoir pressure data is needed perhaps the most, long shuttin-in to take static pressures can be abit problematic due to commercial commitments. There is heavy reliance on planned and unplanned shutins to take useful pressure data used in calibrating reservoir models.
This paper takes a critical look at multiple approaches to estimating robust ultimate recoverable gas volumes with reservoir geology as an essential guide using tow distinc approaches; Detailed 3D simulation model and P/Z estimate method using Piper, McCain and Corredor z factor estimates. Lastly the range of uncertainties of the input data was used to estimate the low base and high cases.
Koma Field lies about 100 Km northwest of Port Harcourt. Structurally, the field can be described as an elongated WNW-ESE trending anticline. Wells drilled at the east and western flank of the K8 structure generally show well developed sand packages with thickness of over 50ft. However, away from these wells, uncertainty in sand distribution is observed as wells drilled in the central part of the structure encountered significantly poorer reservoirs with lower reservoir thickness and quality. The objective of this study was to better understand the depositional architecture and sand distribution for an improved resource volume estimation and most importantly for the optimal placement of a planned development wells.
To reach this goal, an integrated approach of rock physics analysis and seismic interpretation was adopted. Rock physics model was applied over well logs in order to establish a relationship between lithologic facies and rock elastic property. Subsequently, through full stack seismic inversion a P-impedance volume was generated based on geologic information, post-stack seismic data and well logs.
The derived impedance draped on structure revealed that the K8 reservoir is principally a channelized depositional system were the channel axis display low impedance values indicative of high porosity and hydrocarbon saturation. Reservoir quality and thickness is observed to decay significantly away from the channel axis into the channel margin and the interfluve. The impedance result was used to constrain reservoir property distribution and a better estimation of hydrocarbon volume was achieved. A development well intended for a deeper reservoir was also drilled into the K8 reservoir level and tested the prediction from inversion. The well encountered less than 20 ft of sand as predicted from the P-impedance volume. Based on the Impedance map the locations of future infill development well have now been ranked to maximize contact with low impedance-high porosity zones.
Taura, Usman (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Mahzari, Pedram (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Sohrabi, Mehran (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University)
Simultaneous three-phase flow of gas, oil and water is a common phenomenon in enhanced oil recovery techniques such as Water-Alternating-Gas (WAG) injection. Reliable reservoir simulations are required to predict the performance of these injections before field application. However, most commercial simulators are based on Darcy-type formulation requiring the concept of relative permeability. Generally, three-phase relative permeabilities are calculated from empirical correlations, which are based on two-phase relative permeability. However, heavy oil displacement by gas or water can lead to viscous fingering due to the unfavourable mobility ratio between heavy oil and the displacing fluid. In addition, the injection soluble gases such as CO2 can result in compositional effects. Estimation of three-phase relative permeability under such conditions are extremely complex and using conventional techniques for the estimation can lead to erroneous results.
We used the result of three coreflood experiments carried out on a core to generate two-phase and three-phase relative permeability data using an improved history matching methodology that takes into account the instability and the compositional effects in the estimation processes.
The results show that a simultaneous CO2 and Water injection (CO2-SWAG) can be adequately matched using a secondary gas/liquid and a tertiary oil/water relative permeabilities. This is because contrary to WAG in conventional oil recovery, where gas and water open up separate saturations paths, in this case, the water follows the gas saturation path due it's lower resistance as a result of the CO2 dissolving in the oil and reducing the oil viscosity. It is also important to include Pc even in high permeable porous media as we observed that the inclusion of capillary pressure dampened the propagation of the viscous fingers and hence helped the front to become stabilised leading to a better sweep efficiency.