Niger Delta Reservoirs Research Articles

Petrophysical and Geomechanical Analysis to Delineating Reservoirs in the Miocene Niger Delta Region of Nigeria

The application of various petrophysical and elastic metrics has advanced reservoir characterization and provided critical geological formation information. Porosity declines with depth, according to sonic, neutron, and density logs. Lithology, pressure, and hydrocarbons all contribute to this. Formation resistivity and fluid saturation are used to identify hydrocarbon-bearing zones. Because oil and gas are non-conductive, hydrocarbon-containing rocks are more resistant than water. In lithological categorization, gamma logs and the Vp/Vs ratio have helped classify reservoirs as Agbada Formation sand-shale reservoirs. Reservoir elastic characteristics, specifically sandstones, have been studied at various depths. These discoveries have an impact on their brittleness, strength, and failure risk in a variety of scenarios. Hydrocarbon accumulation has been influenced by diagenetic compaction equilibrium in pressure-exposed shale source beds. The research advances our understanding of the geological formations of the Niger Delta and gives practical insights for exploration and production. Decisions on oil and gas are based on hydrocarbon reservoir assessments at various depths, including porosity, fluid saturation, and lithology. Well logs from Wells B001, B002, and B003 revealed the diverse properties of several Niger Delta reservoirs. These discoveries have benefited hydrocarbon exploration and production decision-making significantly.

Improving Oil Recovery Efficiency in Niger Delta Reservoirs Using Corn Starch as a Local Polymer

Polymer flooding is a chemical enhanced oil recovery method that improves the recovery of oil by controlling the mobility of water to oil phase. It uses polymer solutions to increase the viscosity of the displacing water thereby decreasing water/oil mobility ratio (Speight, 2013). The volumetric and displacement sweep efficiencies are positively affected by polymer flooding. The viscosity of the aqueous phase is increased due to the molecular size and structure of the polymer used. The main objective of this research was to study the ability of cornstarch (local polymer) to recover additional oil after conventional water flooding. The objective was successfully achieved by injecting four different unconsolidated samples (sand pack) with cornstarch solution at varying concentration of 500ppm, 1000ppm, 3000ppm, and 9000ppm. From the results of the experiment conducted, it was deduced that Cornstarch has the ability to recover an additional volume of oil about half the volume of oil recovered during conventional water flooding (i.e. if 50% of oil initially in place was recovered during water flooding, cornstarch can recover an additional 25% of the residual oil after water flooding). Also, higher concentrations of cornstarch reduce the recovery factor due to polymer adsorption on the rock surfaces which alters the rock wettability. To reduce the adsorption effect of Cornstarch, it is recommended that the concentration of Cornstarch be measured after the flooding experiments for a better understanding of the adsorption mechanism of cornstarch.

Sand Control and Management Strategies in a Low-Permeability Sandstone Oil Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31002, “Lessons Learned From Optimizing Sand Control and Management Strategies in a Low-Permeability Sandstone Oil Field,” by Babalola Daramola, SPE, Propellio, and Chidubem Martins Alinnor, SPE, consultant, prepared for the 2021 Offshore Technology Conference, Houston, 16–19 August. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. The complete paper presents lessons learned from optimizing sand control and management strategies for an offshore Nigerian oil field after multiple sanding events and well failures. The authors discuss selection of the previous sand control solution, failure root causes, and remediation options considered. Introduction Field E is in a water depth of 500 ft. It features unconsolidated sands interbedded with siltstones and mud rocks, and was developed with five horizontal production wells (A1 through A5), two horizontal water injection wells (W1 and W2), and two gas injection wells (G1 and G2) drilled from an offshore platform. The produced oil from Field E is exported by pipeline to a storage terminal and exported by shuttle tanker to market. The produced gas is reinjected into the reservoir. Field E achieved first oil production in December 2013 and had produced 43 million STB of crude oil by December 2016 (a current oil recovery factor of 13%). Field E’s development wells were completed with 13Cr 5.5-in. tubing, permanent bottomhole pressure and temperature gauges, gas-lift valves, and chemical-injection valves for scale and hydrate management. Initial Standalone Screen (SAS) Selection and Installation Although core samples were collected from two appraisal wells in Field E, a sand-strength study was not completed before drilling because of existing field analog data and cost-saving reasons. Sand-production prediction was based on the Niger Delta reservoir rule of thumb, which assumes that reservoir sands at depths shallower than 10,000 ft true vertical depth subsea (TVDSS) are unconsolidated and are expected to fail. The target reservoir was at a depth of 9,450 ft TVDSS and was expected to produce sand. Field E’s rock unconfined compressive strength was not measured, with 2,000–8,000 psi assumed based on field analog data. SASs were selected for sand control because most neighboring oil fields used them as well. The complete paper includes failure root-cause analyses of all four wells; this synopsis will include analyses of Wells A2 and A3.

Comparative Study of Oil Recovery Factor Determination for Edge and Bottom Water Drive Mechanism Using Water Influx Models

The purpose of this research work is to comparatively study the oil recovery factor from two major aquifer geometry (Bottom and Edge water aquifer) using water aquifer model owing to the fact that most if not every reservoir is bounded by a water aquifer with relative size content (Most Large). These aquifers are pivotal in oil recovery factor (percent%), Cumulative oil produced (MMSTB) as well as overall reservoir performance the methodology utilized in this study involves; Identification of appropriate influx models were utilized for aquifer characterization. The characterizes of the Niger Delta reservoir aquifer considered include aquifer permeability, aquifer porosity etc. Estimation of aquifer properties is achieved by using regressed method in Material Balance Software (MBAL). This approach involves History Matching of average reservoir pressure with computed pressure of the reservoir utilizing production data and PVT data. The computed pressure from model is history matched by regressing most uncertain parameters in aquifer such as aquifer size, permeability, and porosity. Historic production data was imputed into the MBAL Tank Model, the production data was matched with the model simulation by regressing on rock and fluid parameters with high uncertainty. The match parameters were recorded as the base parameter and other sensitivity on aquifer parameters using the Fetkovich model for the bottom and edge water drive. The average percentage increase in oil cumulative volume was 0.40% in fovour of bottom water drive. Further sensitivity on cumulative oil recovered showed the increase in reservoir size with increasing aquifer volumes increases oil production exponentially in bottom water drive whereas edge water drive increased linearly. Aquifer volume, aquifer permeability showed linear relationship with bottom and edge water drive.

Comparative Study of Oil Recovery Factor Determination for Edge and Bottom Water Drive Mechanism Using Water Influx Models

The purpose of this research work is to comparatively study the oil recovery factor from two major aquifer geometry (Bottom and Edge water aquifer) using water aquifer model owing to the fact that most if not every reservoir is bounded by a water aquifer with relative size content (Most Large). These aquifers are pivotal in oil recovery factor (percent%), Cumulative oil produced (MMSTB) as well as overall reservoir performance the methodology utilized in this study involves; Identification of appropriate influx models were utilized for aquifer characterization. The characterizes of the Niger Delta reservoir aquifer considered include aquifer permeability, aquifer porosity etc. Estimation of aquifer properties is achieved by using regressed method in Material Balance Software (MBAL). This approach involves History Matching of average reservoir pressure with computed pressure of the reservoir utilizing production data and PVT data. The computed pressure from model is history matched by regressing most uncertain parameters in aquifer such as aquifer size, permeability, and porosity. Historic production data was imputed into the MBAL Tank Model, the production data was matched with the model simulation by regressing on rock and fluid parameters with high uncertainty. The match parameters were recorded as the base parameter and other sensitivity on aquifer parameters using the Fetkovich model for the bottom and edge water drive. The average percentage increase in oil cumulative volume was 0.40% in fovour of bottom water drive. Further sensitivity on cumulative oil recovered showed the increase in reservoir size with increasing aquifer volumes increases oil production exponentially in bottom water drive whereas edge water drive increased linearly. Aquifer volume, aquifer permeability showed linear relationship with bottom and edge water drive.

Estimating Volume of Shale in a Clastic Niger Delta Reservoir from Well Logs: A Comparative Study

The volume of shale (Vsh) is a critical parameter in petrophysical analysis that enables the accurate estimation of other petrophysical parameters like effective porosity, saturation and Net-to-Gross. This is an important step in characterization of reservoirs as well as valuation of hydrocarbon potentials. GR (Gamma Ray), Neutron and Density as well as Potassium, Uranium and Thorium logs were adopted to estimate and analyze Vsh for sand 4 reservoir interval across five wells using the empirical (GR-linear and non-linear) and Neutron-Density methods. Results show that Vsh estimated by the different methods varied from 0.24 - 0.39 for the GR linear method (highest), 0.12 - 0.24 for the Larionov method (intermediate), and 0.04 - 0.28 for the Neutron-Density method (lowest). Although the Neutron-Density method gives the lowest values of volume of shale, this does not translate to the most accurate and reliable results. This may be attributed to the non-singularity in measurements and varying sensitivities of the well logs used in this method as well as the complexities of the wellbore condition. The GR non-linear (Larionov) method provides consistent and comparable volume of shale estimations with the neutron-density method than the linear GR method and consequently, the non-linear GR method is recommended for estimation of Vsh in the studied field.

Robust optimisation of water flooding using an experimental design-based surrogate model: A case study of a Niger-Delta oil reservoir

Reservoir simulations are often applied in oil field development to predict and optimise the performance of the production process and improve the decision-making process. This process is made complex by the need to account for uncertainties in the simulation model input parameters. The classical Markowitz optimisation model is an approach that can be applied for reservoir performance optimisation considering uncertainty. However, numerous full-physics simulations are required for the optimisation procedure to work. To overcome this challenge, we deploy a surrogate model of total oil production for the robust optimisation of waterflooding in a Niger-Delta reservoir. Using this approach, we reduce computational costs and consider four uncertain geological variables in a robust application of the optimisation routine. To adequately capture the uncertainties in the geological model, we apply 100 realisations of the reservoir model. In our presented case, we show that by applying a proxy model of the cumulative oil production in the study, the computational costs of the optimisation routines are significantly reduced. Overall, we perform more than 10000 proxy model evaluations requiring 4 days and saving 417 days of computation time which is required if full-physics simulations were applied in the optimisation routine. As a result, we can make decisions accounting for uncertainty and the potential implications for variation in the development and operation of the field.

Performance Prediction of Niger Delta Reservoir BUZA Using Allocation Tool

Predicting the performance of reservoirs help engineers to evaluate reserves, carryout development planning which requires thorough understanding of the reservoir characteristics, develop a model that can mimic the physical processes occurring in the reservoir such that forecast can be made with reasonable accuracy. This study used the material balance software, MBAL which is an allocation tool to evaluate the reserves of reservoir Buza and thereafter predictions were carried out on the reservoir. This was achieved by determining the dominant energy in the reservoir, performing non-linear regression on the uncertain parameters and performance predictions to obtain cumulative oil production and recovery factor. The results obtained showed that water injection at an average rate of 22000STB/D was the main energy in the reservoir providing about 68% of the total energy in the system. The recovery forecast at 31/12/2022 will be 42.8% with cumulative oil production of 98MMSTB. These results are necessary and important for reservoir engineers and policy makers in reservoir management.

Volumetric and Material Balance Methods of Reserve Estimation: A Comparative Study using Niger Delta Reservoirs

This paper investigated the estimations of reserve in place in four Niger Delta Reservoirs using both the Volumetric and Material Balance (MB) methods comparatively. The Volumetric estimations started from the planimeter readings while the MB method used plots from the Havelena and Odeh formats in its estimations. Reservoir “A” is a saturated oil reservoir, no water drive, and negligible rock and fluid compressibilities; Reservoir “B” is a saturated oil reservoir underwater drive at encroachment angle of 70o; Reservoir “C” is an undersaturated oil reservoir under solution gas drive, while Reservoir “D” is a gas reservoir without water influx. There were good to the very good correlation between the results obtained by both methods except in the case of “D” where an extension of the reservoir to another occurred and so the Volumetric method gave a value of 4.48MMMSCF as the value of gas in place while the MB method gave a value of 9.15MMMSCF. The MB method was recommended to give better accuracy though very cumbersome to evaluate.

Integrating Old and New Data-Evaluation Techniques for Effective Reservoir Characterization of Southeastern Niger Delta Reservoirs

Summary The value of data integration has been proved in assessing the thin-bedded H4 reservoir and the stratigraphically natured H5 reservoir in UKU Field, southeastern Niger Delta, toward planning effective development strategies for depletion. Reservoirs of these definitions pose problems during mapping from seismic for well planning and drilling activities, as well as at the production stage. Data for this work consist of a recently acquired full-stack, 3D ocean-bottom-cable (OBC), prestack-time-migrated (PSTM) seismic data; well logs from five vertical wells; core information; and modular-dynamic-test (MDT) data. Seismic-attribute maps and extracted geobodies revealed the reservoir extent within the limit of seismic resolution (≈27 ft), while petrophysical analysis indicates the reservoirs to be of excellent flow-and-storage quality. MDT data reveal the hydrocarbon fill to be of medium-to-heavy grade. While water production was decided not to be probable for H4 reservoir depletion, it is of certainty in H5 reservoir production. Mapping showed that the field is separated into two fault blocks (FB1 and FB2) on the basis of the difference in water-contact levels, with calculated oil volume of 4 million BO (FB1) and 12 million BO (FB2) in H4 reservoir and 12 million BO (FB1) and 2 million BO (FB2) in H5 reservoir. Gas reserves in H4 sand were calculated to be 480 MMcF in FB2.

Effect of Matrix Acidizing on The Performance of Selected Niger Delta Reservoirs

The performance of matrix acidized selected wells from the Tertiary sandstone reservoirs in the Niger/Delta was evaluated, Data obtained was used to evaluate flow efficiency and production performance before and after acidizing. The results showed that Matrix acidizing proven to be the best stimulation technique employed in recent years to remove near wellbore damages and invariably increase productivity. The analysis involves the post net oil and percentage increase in oil achieved after acidizing, well inflow performance quality indicator and decline rate analysis.

Permeability Model for Nigerian Oil Sand as Candidate CO 2 Storage Reservoir

This research examines the challenges associated with storing captured CO 2 in the Niger-Delta reservoirs by examining the effect of the stored gas on the reservoir rock sample. Mitigation against increasing CO 2 in the atmosphere is uppermost in environmental research due to its negative effects and therefore there is need to explore all possible reservoirs, apart from abandoned crude oil reservoirs, for CO 2 storage. In this research, a model was developed to study permeability variation during CO 2 injection to oil sand as a candidate CO 2 storage reservoir. Four existing permeability models of Tixier, Timur, Coates-Dumanoir and Aigbedion were employed together with a proposed model. The proposed model was a combination of irreducible water saturation equation from Timur model and the Coates-Dumanoir permeability equation. The proposed model took cognizance of changing porosity phases, since the injected CO 2 is reactive and affects the properties of the reservoir rock. The model equation obtained is the model gave permeability value ranging from 16.94 to 2.74 mD for Imeri oil sand. In comparison, the Timur model gave permeability values from 1.45 to 0.002 mD; Tixier value ranges from 42.85 to 0.01 mD; Coates-Dumanoir value of 287.72 to 7.49 mD while value given by Aigbedion rangs from 9.01 to 2.6 mD. In the course of the research it was discovered that Imeri oil sand formation, though has very high porosity which could be a pointer to early stage leakage, is highly reactive with the injected CO 2 . This reactivity is a good condition for permanent storage of the injected gas and is therefore recommended, with reservation, as a potential CO 2 storage reservoir. The proposed model will also give the expected CO 2 gas mobility with increasing period of injection. Key words: CO 2 storage; Oil sand; Porosity variation; Permeability; Permeability model

Use of Actual Dimension in the Percolation Model for the Calculation of Breakthrough Time in Oil Recovery: Case of Some Niger Delta Reservoirs

This paper calculates breakthrough time for some Niger Delta reservoirs using a percolation model. The model is less cumbersome and time saving when compared with traditional methods such as the Buckley-Leverett method. By incorporating some reservoir specifics, such as actual reservoir dimension, into the model used in this paper, better results which approximate empirical values closely are obtained. The fact that breakthrough time is reservoir specific is confirmed. Keywords: Oil recovery, Percolation model, actual reservoir length, Niger Delta, Water Drive Mechanism, Breakthrough time.

Estimation Of Height Of Oil -Water Contact Above Free Water Level Using Capillary Pressure Method For Effective Classification Of Reservoirs In The Niger Delta

An estimate of oil-water contact (OWC) and the understanding of the capillary behaviour of hydrocarbon reservoirs are vital for optimum reservoir characterization, hydrocarbon exploration and production. Hence, the height of oil-water contact above free water level for different rock types from some Niger Delta reservoirs were estimated here. Data obtained from oil-displacing brine (drainage) capillary pressure tests using refined oil as simulated brine formation or reservoir fluid on various rock samples were utilized to illustrate the basic capillary behaviour of ten hydrocarbon reservoirs within Niger Delta of Nigeria and to estimate the (OWC) above Free Water Level. Almost all the samples show plateau prominence and high permeabilities of (422-4110) x 10 Hm at very low displacement pressures with well sorted grains which is indicative of good reservoirs This is further confirmed by their low heights of 100% water saturation above free water level of 2.11m, 1.41m, 2.46m, 1.05m, 2.07m, 1.72m, 1.79m, 1.76m, and 1.05m, and corresponding to a depth range of 3030 to 3261 m which indicate good quality reservoirs. Only one sample showed evidence of low yield reservoir with high height of 5.62m at a depth of 3266 m. The derived knowledge of water density, oil density and saturation height function adequately estimates the quality of reservoirs and classify them in terms of prominence of the plateaux and channels. The results show that the typical Niger Delta reservoirs are of good quality as confirmed by the relatively low shale presence. Keywords: Oil-water contact, capillary pressure, reservoir characterization, saturation height function and permeabilitiesNigerian Journal of Physics Vol. 19 (2) 2007: pp. 303-311

Laboratory evaluation of acid effectiveness for well stimulation in the Niger Delta, Nigeria

This paper presents data that attest to the need for acid effectiveness evaluation for determining formation specific optimum acid recipes prior to acid work in the Niger Delta reservoirs. The results of a complete acid effectiveness evaluation study for two oil reservoirs (A and B) and one aquifer system (C) show that the regular mud acid (RMA) commonly used for stimulation in the Niger Delta may be damaging under many circumstances. The extent of damage by the RMA and the improvement through properly designed recipes are shown by laboratory analytical tests that are scaled to field and well condition. The analytical work includes characterization of the reservoirs. The hydraulic unit (HU) concept that combines the geological (texture and mineralogy) and petrophysical (porosity, permeability and capillary pressure) controls of the rock quality was used to delineate the reservoirs into units with similar fluid flow characteristics. This zonation enabled the determination of the acid recipes by HUs and thus facilitated the extrapolation to uncored intervals or wells. The optimum acid sequences for each HU were determined on the basis of pre- and post-stimulation indices, compressive strengths and critical velocities. Visual observations of core material at the end of the acid flush and iron sequestrant analysis were also used as interpretation tools.

A Template for Enhanced 3-D Geological Modelling of Wave-Dominated Deltaic Reservoirs from the Tertiary Niger Delta: ABSTRACT

Quantitative 3-D geological models of Shell's Niger delta reservoirs are now routinely used for well and field development planning, simulation input and reserves booking. A review of these models, built with Shell's reservoir modelling package Geocap, has highlighted the successes and potential pitfalls of 3D reservoir modelling and has led to a template for better modelling of wave-dominated deltaic reservoirs. The key issues fall into two categories. The first concerns the use of soft geological knowledge. Conceptual models are a prerequisite for quality 3-D reservoir models and meaningful results can be obtained only if the geologist has a mental 3-D picture(s) of the reservoir which is used to steer the modelling. The decision to use stochastic techniques is crucial. In wave-dominated deltaic reservoirs, uncertainty may be better handled by a series of deterministic scenarios rather than many stochastic realizations. Sequence stratigraphic correlation tools and the definition of meaningful and recognizable facies types and flow units also determine the quality of the model. Integration between the petroleum engineering disciplines is the second category. The interface with the reservoir engineer is particularly important; the relevant level of geological detail must be identified and preserved during upscaling and flow simulation. Reservoir engineering andmore » seismological data must be used to refine or validate alternative scenarios in an iterative loop. 3-D modelling is a tremendous business opportunity, but it demands more geological skills as well as a fully integrated, multidisciplinary approach.« less

Predicting Gas, Oil, and Water Intervals in Niger Delta Reservoirs Using Gas Chromatography

Formation evaluation experts usually have little difficulty in interpreting wireline logs to assess the type of reservoir fluid (oil/gas/water) in sand-shale sequences. This assessment is usually accomplished by a combination neutron-density tool that detects low hydrogen and low electron densities typical of gas zones, and the repeat formation tester (RFT), which uses both the pressure gradient and sample acquisition techniques to evaluate reservoir fluid. In the Niger Delta, however, many of the sands exhibit a poor neutron-density response to gas, and RFT testing has been largely eliminated because poor hole conditions commonly result in stuck tools. Oil fingerprinting of residual hydrocarbons from sidewall core extracts can provide an independent means of identifying eservoir fluid type. In conjunction with the Nigerian National Petroleum Company, we completed numerous chromatographic analyses on solvent extracts of sidewall core samples from various wells in the Mefa field, offshore west Niger Delta. Oil fingerprints of sidewall core extracts clearly reflect the type of hydrocarbons in the reservoir. Fingerprints of oil-saturated sands are typical of topped (C15+) whole oils, whereas fingerprints of hydrocarbons extracted from the gas-dominated sands show an abbreviated hydrocarbon distribution more typical of gas condensates. Fingerprints of extracts from water-productive intervals show a further abbreviated signature, suggesting that higher molecular weight hydrocarbons did not migrate into these intervals. These signatures are distinct and intact despit poor sample preservation due to prolonged storage of up to 3 yr. Additional applications of this technique include the reevaluation of older wells that lack modern wireline measurements, but have sidewall or conventional core material available, and in thin or low-permeability sands that may not yield definitive RFT or wireline-log responses. Application potential for this technology is worldwide and includes the Gulf Coast of the United States, Canada, Indonesia, and Papua New Guinea.

Predicting Gas, Oil, and Water Intervals in the Niger Delta Reservoirs Using Gas Chromatography: ABSTRACT

Predicting Gas, Oil, and Water Intervals in the Niger Delta Reservoirs Using Gas Chromatography: ABSTRACT

High Resolution Tectono-Sedimentary Modelling of Niger Delta Reservoirs: ABSTRACT

High Resolution Tectono-Sedimentary Modelling of Niger Delta Reservoirs: ABSTRACT

Niger Delta reservoir geology: historical growth of the sedimentological model and its application to field development

Abstract In 1953 when the exploration in Nigeria moved towards the Niger Delta, it was realised that the recent delta could be used as a guide to the past. Consequently many studies were carried out between 1953 and 1964, ranging from surveys of the shallow offshore, the coastal zone and the rivers to an extensive shallow coring campaign (1960–62). The studies of the recent delta were soon augmented by the analysis of cores from several newly discovered fields (1963–69) and also by the description and grain size analysis of numerous side-wall samples. Around 1970 the basic facies types comprising the individual deltaic cycles of the hc-bearing paralic sequence were well established. The facies types occur in a very repetitive pattern of combinations and successions which facilitates recognition and correlation. A fairly reliable system of diagnostic criteria was worked out based on petrophysical logs and side-wall samples and calibrated by the cores and the recent delta. With the sequencial introduction of new logging tools the diagnostic methods are being refined while additional cored wells continuously enlarge the data base. Detailed seismic analysis at reservoir level is showing considerable promise for sand body delineation. For each facies a representative data base of sand body geometry could be compiled based on detailed reservoir correlations and recent examples. There is a good understanding of typical permeability and grain-size distributions. Knowledge on shale intercalation continuity is particularly useful in the planning of well completions to retard gas or water breakthrough to the well bore. It was shown that permeability can be computed from log derived porosity and grain-size distribution measured on side-wall samples. The practical value of the reservoir geological research lies in the possibility to correlate and model reservoirs in a reliable and consistent manner. Reservoir and well behaviour can be predicted and where necessary reservoir simulation models can be constructed. Continuous updating of reservoir studies has demonstrated the validity of this approach by checking past predictions and analysis of infill wells. In this way the production planning and reserve estimation is given a solid base.