bluuebunny/crossref_metadata_2025 huggingface dataset:
Simple Quantitative Characterisation and Grouping of Electrofacies in Shaly Sandstone Formations
Authors: Lawal Kazeem A. , Ukaonu Cyril E. , Ovuru Mathilda I. , Eyitayo Stella I. , Matemilola Saka
Published: July 2017

Electrofacies modelling, which includes identification and grouping, is a critical part of reservoir characterisation. Because it governs the estimation and distribution of key rock and rock-fluid properties, the electrofacies model, to a large extent ((if augmented with core-derived information), determines the quality of static and dynamic reservoir models. Unfortunately, owing to the lack of a universally acceptable method, the outcome of electrofacies modelling is not always unique. This explains the usual difficulty in achieving a meaningful comparison of different reservoirs or correlating different packages, even with the same set of well logs.

To address the problem, this paper presents a set of mathematical models and simple workflows for quantitative characterisation and grouping of electrofacies in shaly sandstone formations. The gamma ray, density, and neutron, which are commonly available lithology-indicating and absolute-value reading logs, are integrated to define a quantity called composite shaliness parameter. The use of a simple scaling rule ensures that the values of the shaliness parameter are limited to the 0 - 100% range. To make the model universally applicable, the scaling of the shaliness parameter covers the ranges of values of the indicated logs in most shaly sandstone formations.

Although the models and workflow are intended to be universally applicable to all shaly sands to enable global benchmarking of formations as may be necessary, provision is made for local applications. In the latter cases, a simple procedure for adapting the scaling rule to specific local problems is presented.

Using field examples from the Niger Delta, the validity of the proposed method is examined. It is evaluated against mobility tests, core analysis and spectral gamma-ray log, which are techniques known for better reservoir characterisation at different scales. It is found that the results of the proposed method are in satisfactory agreement with findings from these reference characterisation techniques.
Well Clean Out and Acidization of a Deepwater Intelligent Completion Well – A Case History
Authors: Awotiku Oluwabiyi , Hackney Dave , Ledergerber Alan , Ugah Ibrahim , Femi-Saliu Bola
Published: July 2017

Agbami Well-BB was completed as a dual zone frac pack intelligent completion. Barely a month after the well was put on production, while carrying out optimization on the well to increase production, flow from the upper zone decreased and further testing indicated that the zone’s production had dropped significantly. From the analysis of the well, it was observed that productivity decrease was as a result of plugging upstream of the interval control valve (ICV). Analysis further showed that the plugging in the well was speculated to be caused by lost circulation material (LCM) pumped during the completion of the well, when significant fluid losses were observed through the frac pack after a fishing operation unsettled the sand control packer.

To clean out the well and free the completion of the restriction caused by the LCM, the multi-disciplinary team set up recommended the use of the established method used for acid stimulation in Agbami. This involves the use of a subsea support vessel equipped with dynamic positioning and remote operating vehicle (ROV). Utilizing the subsea support vessel, customized dual conduit system utilizing two coil tubing strings connecting to the gas lift valve on the subsea tree were used to bullhead acid into the well.

The well clean out operation increased production from the zone by about 8000 bopd and restored the zone to its initial productivity. Lessons learned include:Understanding the cause of the plugging was important in determining the acid recipeAll initial produced fluid from the flowback was routed to a single tank for isolation to prevent entry of possible contaminated fluid into the FPSO process system.

This technical paper describes the troubleshooting on the well, acid selection process, well clean out and acidization procedure/operation, the results, best practices and lessons learned.
Successful Narrow Margin Drilling in a Brown Field: Planning, Execution Strategies and Lessons Learnt
Authors: Judith George , Onyinye Reginald-Ugwuadu , Fred Timibitei , Yemi Erinle
Published: July 2017

Most operators’ business strategies had been to develop oil prospects, leading to several years of production from shallow formations. However, with growing domestic gas production and sustaining gas export in Nigeria, there has been a drive to develop gas reserves. This resolve to develop gas reserves to fulfill energy demands has led to exploring, appraising and developing deeper prospects in brown fields. Reaching these deeper horizons which are usually characterized by overpressured sands would mean drilling through shallower and most times depleted reservoirs due to several years of production. This poses very peculiar challenges as the margins between the pore pressure and the fracture resistance of the formation matrix is very low. This primarily determines the maximum allowable open hole that can be drilled for each section driving the well configuration in terms of hole sections and casing scheme. Drilling risks and uncertainties are increased with narrow margin drilling and these can range from lost circulation, equivalent circulating density (ECD) management, borehole stability, differential sticking, well ballooning, kicks among others. These are expensive drilling risks that are well articulated with mitigations put in place before drilling commences, as they are known to have cumulatively cost the oil and gas industry several billions of dollars.

This paper highlights the detailed design and planning towards a narrow margin drilling campaign on a gas field in the Niger Delta herein referred to as Alfyxx Field. It will also examine key experiences gained from drilling seven wells, Alfyxx 1-7; the adopted proactive strategies for different scenarios, encountered drilling challenges and recovery measures leading up to successful well delivery. The impact of unplanned challenges on cost and time in achieving the overall campaign objective is also discussed.
Using Compositional-Grading Simulations to Assess Gas-Oil Contacts: Practical Cases from the Niger Delta
Authors: Eyitayo Stella I. , Lawal Kazeem A. , Ukaonu Cyril E. , Ovuru Mathilda I. , Sanyaolu Adeniyi A. , Otubanjo Modupe A. , Olushoga Elizabeth O. , Matemilola Saka
Published: July 2017

Encountering a reservoir in either a gas-down-to (GDT) or an oil-up-to (OUT) situation poses a challenge to development planning and reservoir management. The resulting uncertainties in the distribution, in-place and recoverable volumes of oil and gas may jeopardize expeditious execution of the field development project. To confirm the presence or absence of either oil or gas and establish a possible gas-oil-contact (GOC), in some cases the drilling of an appraisal wells(s) may be required. This paper describes a method that does not depend on dedicated appraisal wells to reduce GOC uncertainties and proves to be a valuable method to de-risk planned reservoir developments.

Where credible pressure-volume-temperature (PVT) data are available from the subject reservoir, compositional-grading simulations (CGS) can be employed to evaluate the presence (or otherwise) of a GOC within a vertically continuous reservoir column. From a thermodynamic standpoint, the GOC is that depth at which the reservoir fluid transits from being gas-like to oil-like, and vice-versa. Considering some saturated and undersaturated oil reservoirs in the Niger Delta as case studies, this paper demonstrates the applicability of a combination of PVT and CGS to de-risk the presence of GOC without resorting to either a new well or a pilot hole.

In the cases where well logs have established GOC, blind tests show excellent agreement between CGS results and well logs. Similarly, CGS accurately suggests the absence of gas-like fluids within the proven undersaturated oil reservoirs examined.

Finally, the results of this study will document that CGS is reliable and cost-effective for reducing GOC uncertainties and de-risking field development projects. Consequently, this method is recommended whenever credible PVT data are available.
Sustainability of Deep-Offshore Exploration and Production E&P Project Development under Low Crude Oil Price Regime: Empirical Evidence from Nigeria
Authors: Akinlawon Adeyemi J. , Iledare Omowumi O.
Published: July 2017

Petroleum E&P operations in Nigeria were virtually restricted to land, swamp and shallow offshore until 1993. The Federal government, in its quest to open a new frontier in oil and gas exploration, allotted the first set of deep-offshore blocks to some international oil companies (IOCs) and indigenous oil companies, in 1993, to operate under contractual fiscal arrangements. The adoption of the contractual fiscal system was to provide a suitable agreement structure for encouraging investment in offshore acreage. As at year end 2015, there were seven deep-offshore producing fields, which contributed about 40% of total oil production in Nigeria.

There are a number of deep-offshore fields on the queue for investment decisions, but progress has been inhibited because of several factors, including the low crude oil price regime and lack of fiscal instruments and terms for natural gas development. The proposed Nigeria National Petroleum Policy of November 2016 estimated the cost of producing a barrel of oil in Nigeria as $28.99/bbl. At this high estimated unit cost, coupled with the sustained volatility in crude oil prices, the deferment of cost recovery and declining earnings from the field development projects have become inevitable.

This paper evaluates the impact of current fiscal provisions on deep-offshore developments and estimates thresholds of oil price, reserves and cost of services, with the view of determining optimal terms that will encourage new field developments. The model framework adopted for this paper is based on the generic discounted cash-flow modelling with considerations for risk and uncertainty analysis using Monte Carlo simulation process.

E&P investment measures are derived by solving a discounted cash flow equation iteratively in a coded Excel spread sheet model. Using estimated responsiveness measures, the paper investigates how to adjust contractual fiscal terms and instruments to make investing in E&P ventures in deep-offshore Nigeria offer satisfactory returns under low price regime. The significance of the impact of fiscal agreement terms and instruments using Monte Carlo simulation provides a framework to compare the performance of deep-water projects.
Simulation Model Robustness Check- Indicators of Pessimistic Models Pre and Post History Match Case Study Fotis Reservoir
Authors: Dennar Linda , Emelle Chima , Suleiman Ahmed , Olugbenga Daodu , Nwachinemere Uche
Published: July 2017

The essence of reservoir simulation is to forecast field performance, ultimate recovery and to evaluate the effects of different operational conditions on recovery while keeping the economics of each scenario in view.

It is important to note that in simulation one of the characteristics of a history match is that the outcome is a non-unique solution and it is influenced by many factors including porosity, permeability, thickness, saturation, PVT, relative permeability etc. A combination of these parameters result in a match and is not unique to that reservoir, thus this may not perfectly represent the condition of that reservoir.

A common area of struggle is the transition of a model from pre-production vintage to a history matched solution where the only additional data available is production without having to build the model from scratch. It is therefore important to have a rule of thumb to validate the robustness of a simulation pre-production forecast prior to the onset of production. The effect of this may result in a pessimistic or overly optimistic model which translates to a non-representative reserves addition.

The Fotis reservoir has been used as a case study to highlight the importance of a robust pre-production forecast prior to the onset of production and history match. Fotis is a NAG reservoir with a fault assisted dip closure trap. The reservoir sand is interpreted to be deposited in a shallow marine setting (consisting of shoreface and channels deposits). Reservoir properties are good (Avg Por. 17%; perm ~700 mD). Base case In-Place volume is about half a Tscf. Some 27% of the inplace volumes have so far been produced.

The reservoir simulation model went live in 2010 without a history match because there was no production and pressure data. Production commenced in 2011. Well and Reservoir Management Philosophy for the reservoir was to produce the well at 100MMscf/d thus this was captured in the model though model forecast plateau seemed conservative for the low case model. The model was history matched in 2015 post the acquisition of pressure data. Inability to achieve history match within acceptable limits on the low case, even as the current well production rate of 100MMscf/d was sustained confirm the conservative nature of the low case model.

This paper analyzes and highlights pitfalls to be avoided in the pre-production models and how multi-disciplinary solutions could drive a more representative output that supports robust life cycle predictions from the model.
The Use of Reservoir Navigation Service RNS with VisiTrak Geospatial Navigation and MCWD Inversion Analysis Service in Nigeria on a Deepwater Project: Geosteering in Thin, Faulted, and Heterogeneous Reservoir
Authors: Ndokwu C. , Okowi V. , Foekema N. , Wharton P. , Brock P. , Holbrough D. , Ndefo O. , Agbejule A. , Delpeint A.
Published: July 2017

Variable reservoir thickness, heterogeneity, and presence of geological truncations are some of the challenges inherent in draining complex reservoirs. These challenges affect the depth of detection of some formation evaluation tools, the ability to optimally place the well in the target horizon, and the ability to remain in the sweet spot throughout the drain length. To mitigate these challenges, reservoir navigation service with fit-for-purpose tools and robust software is required.

This paper is a case study of the application of the VisiTrak™ tool and Multi-Component-While-Drilling (MCWD) inversion software (Sviridov et. Al., 2014) in the geosteering of Well-X. VisiTrak is an extra deep-reading azimuthal propagation resistivity tool. MCWD is software that essentially creates a geological earth model from the readings of azimuthal propagation tools. It is multi-layer inversion software. Well-X is located in offshore Niger Delta and the target reservoir consists of several individual turbidite complexes and stacked channels.

The successes recorded in this geosteering case include accurate subsurface structural interpretation, reservoir characterization, and achieving well objective in terms of net sand drilled. This paper demonstrates the importance of reservoir navigation in accurate well placement, the benefits fit-for-purpose tools bring to geosteering complex reservoirs in the Niger Delta and shows the value of data integration in reservoir navigation service.
Mathematical Analysis of Oil Displacement by Water in Heterogeneous Reservoirs
Authors: Nwaka Nnamdi A. , Isehunwa Sunday O.
Published: July 2017

Prediction of reservoir performance during water displacement process is a routine procedure for homogeneous reservoirs but complicated in heterogeneous reservoirs. The Stiles method has consequently been used over time in the industry for such reservoirs. This method, however, is evidently time consuming and tedious as the varying permeability values are reordered and lumped. This paper applies the Welge procedure to a stratified reservoir without reordering or lumping of permeability with the aim to ensure improved productivity by more proper planning, more efficient use of resources and determination of the economic viability of the project. This paper also seeks to formulate a procedure that can judiciously handle even larger sets of permeability values to produce more accurate result

A fractional flow equation was derived for any number of layers to generate a single fractional flow curve (FFC). Injection inflow into a layer was determined using the layer capacities and this facilitated calculation of times to breakthrough and times to attain a particular saturation after breakthrough. A formula was then derived to determine the oil produced at any instant. A software was designed for the entire procedure to ensure faster and more accurate predictions. Results showed that heterogeneities had no effect on the microscopic displacement and thus the fractional flow curve remained unchanged whether the reservoir was heterogeneous or not. Heterogeneities affected only the total flow in the distinct layers and thus times to attain specified average water saturations. The results of oil recovery obtained were compared to those obtained using the Stiles method to demonstrate that this method is faster without loss of accuracy.
Finite Element Analysis of Cement Sheath Behaviour Under Changing Load Conditions in HPHT Wells: A Niger Delta Case Study
Authors: Olusuyi Awe Sunday
Published: July 2017

The deterministic analysis of cement sheath behavior under varying wellbore loads aids design and deployment of cement. Assurance of the ability of cement to achieve and retain zonal isolation is safety critical requirement for the successful drilling of a well and subsequent production operation. Exploitation of hydrocarbon resources in more challenging environments such as high pressure and high temperature (HPHT) intervals continues to push the frontier of cement design for zonal isolation purpose.

Severe temperature in HPHT environments has been known to result in degradation of cement over time. In addition to this risk of thermal degradation, the cement sheath is also subjected to varying pressure loads during well construction and production operations. The implication of the pressure load cycles is that mechanical properties of conventional cement recipe may not able to guarantee long term zonal isolation especially in HPHT wells with the high magnitude of pressure load variations. Proper understanding of the scale of the varying pressure loads in the wellbore and the corresponding stresses generated in the three components of the wellbore system (i.e. casing, cement and formation) is pivotal to designing a suit for purpose cement recipe that will eliminate loss of zonal isolation during the entire life span of a well.

Finite element analyses tools have been successfully used to gain knowledge of material behavior when subjected to varying stresses. In this project, investigation of the cement sheath behavior using finite element analysis was carried out to determine the mechanical properties of cement required to ensure retention of zonal isolation under continuously changing wellbore pressure loads during drilling and production phases of typical HPHT well in deltaic depositional environment. The analysis also aided drilling operation optimization in the ongoing HPHT campaign by Shell Petroleum Development Company in the Niger Delta.
Further Insight into Flow Contribution of Commingled Turbidite Reservoirs – A Deepwater Case Study
Authors: Chukwueke Njoku , Itua Osazua J. , Olubunmi Arogun , Chinenye Chukwuneke , Ipalibo Horsfall , Ringim Mohammed Hafiz
Published: July 2017

The Ajanla field is a deepwater turbidite field located offshore Nigeria. PLT data acquired across two turbidite "A" and "B" reservoirs in the Ajanla-P well before production commenced in the field demonstrated flow potential of the reservoirs at a proportion of 85% | 15% and 100% | 0% drainage contribution at flowrates of 12,000 bbls/day and 5,000 bbls/day respectively.

New infill drilling results and 4D seismic data acquired several years after production commenced have provided significant insight in the sweep pattern in the reservoirs. The 4D seismic data has indicated strongly channelized sweep in reservoir "A" but negligible pressureand saturation changes in reservoir "B". This interpretation was further verified by the results of the in-fill wells which showed low remaining hydrocarbon saturations in "A" but near virgin saturations in "B" after five years of commingled production from both reservoirs through Ajanla-P.

This paper investigates the interplay of several factors such as well completions integrity and water injection constraints critical to effective development of turbidite reservoirs and also discusses how the various data sources were integrated to improve understanding of the dynamics between reservoirs "A" and "B" and their possible impact on the future development of the reservoirs.
Pressure Balanced Modelling for Generating Production Forecast in an Integrated Oil and Gas Asset. A Pilot Case Study
Authors: Nwaokorie Chukwuemeka , Ekong Inem , Vlaardingerbroek Rene
Published: July 2017

Integrated Asset Pressure Balanced Modelling involves the coupling of the reservoir dynamic and surface facilities models into a single integrated tool that allows the simulation of the whole oil/gas field system.

The pilot study was conducted on the company’s export gas portfolio using pressure balanced model (PBM) in a Hydrocarbon Field Planning Tool (HFPT) platform.

In the simulation, HFPT uses a pressure-balanced solution of the integrated system: from the reservoir(s), through wells and surface facilities, to the delivery point. A wide range of fluid models is available, from simple gas-condensate and black oil PVT models to multi-component models with EOS flash calculations. HFPT provides optimization functionality for maximizing the returns in oil and gas fields, while accommodating operational preferences for production allocation and network constraints.

The results from this pilot indicate a successful integration of all subsurface discipline and surface data to create a pressure balance model that support our export gas supplies to NLNG. It also provides the platform to test the impact of the supply/facility constraints on our different portfolio projects.
An Unconventional Approach to Gas Injection - A Niger Delta Field Case Study
Authors: Kallel Narjes , Oni Olugbenga , Heiland Juliane , De Gennaro Vincenzo , Ramaswamy Sunil , Arasi Quadri , Campero Manuel Flores , Odumboni Idowu , Chemmarikattil Rohan , Osauzo Sam , Basu Subhayu , Otevwemerhuere Joseph
Published: July 2017

The use of gas injection and storage approach in enhanced oil recovery (EOR) is receiving increasing attention as an efficient solution to mitigate the effects of anthropogenic greenhouse gas emissions in the atmosphere, improve production by means of increasing static reservoir pressure, and allow optimized utilization of produced hydrocarbons as a function of actual consumption.

During gas injection a geological trap (i.e. active or abandoned reservoir) is used to store excess gas that can be eventually produced for future utilization. This process generates changes in pore pressure within the rock's porous space, affecting simultaneously the state of stress inside the reservoir and in its surroundings. These changes of the state of stress can be at the origin of instability mechanisms associated with fracturing inside and outside the reservoir and of reactivation of existing discontinuities (faults and fractures). If reactivation occurs within the caprock, this could lead to possible reservoir sealing failure and thus leakage of the stored gas at surface. Therefore, deformation of caprock and fault integrity must be assessed to properly manage containment performance and leakage-related risks. Given the intrinsic 3D nature of the problem, to ascertain the feasibility of injecting and/or re-injecting natural gas back into producing formations, it is essential to perform numerical simulations to capture the link between concomitant pressurization and /or depletion. The modelling is done with a 3D reservoir simulator and in-situ stresses changes are obtained by means of a 3D coupled reservoir geomechanics simulator.

A feasibility study of gas injection and storage in a producing reservoir was performed using coupled geomechanics modeling within an E&P software platform. The process started from single-well geomechanics analysis and then passed through 3D structural characterization and properties modeling, in-situ preproduction stress modeling, dynamic simulation, and, finally, injection modeling. Analyses were carried out using injection pressure modeled dynamically in an industry-standard reservoir simulator. This allowed various injection scenarios to be explored, providing a 4D characterization at various time steps in the future of the state of stress within the reservoir and its surroundings. Results highlighted the main risks, which are related to loss of sealing for the caprock and reactivation of induced faults, as well as uncertainties associated with input parameters.
Improving Gas Dehydration Using Pre-Inhibited Glycol
Authors: Achara Azubuike , Osuagwu Michael
Published: July 2017

A report is presented on natural gas dehydration performance of dehydration units in two different plants using a pre-inhibited glycol/antifoam/pH adjuster blend versus neat glycol with periodic injection of anti-foam and pH adjuster inhibitors.

To investigate the effect of using pre-inhibited glycol, two plants, each containing two gas dehydration trains (modules) were utilized such that while one train employed neat glycol with periodic chemical injection, the other employed the pre-inhibited blend with both trains running simultaneously. The two facilities were selected based on their history of poor dehydration and glycol regeneration performance and internal corrosion while using neat glycol. Performance was assessed based on resulting gas dew point, dissolved iron content, pH stability and glycol loss rate (in form of top-up frequency).

In all four KPIs selected for this study, the pre-inhibited blend out performed its counterpart significantly despite initial concerns that the fixed inhibitive properties of the blend may not be robust enough to address varying operational conditions. Glycol loss rates decreased by 67% and this led to a corresponding reduction in operating cost. Gas dew point was further depressed by more than 5°C thereby restoring the two facilities to within gas export specifications in compliance with Gas Sales Agreements (GSA). pH stability remained within the buffered zone of 8.5 – 10. As evinced by the decreased loss rates, foaming did not occur at this pH range as opposed to typical experience with neat glycol. Corrosion, being inherently more chronic than acute was not measured in this trial, although there was a progressive decrease in dissolved iron content with the pre-inhibited blend. These results imply that not only can dehydration performance be increased and operating costs decreased, but also that the traditional installation of pH adjuster and antifoam injection skids may prove unnecessary for future facilities

The insights made with this new pre-inhibited glycol blend approach presents strong evidence of an opportunity for significant reduction in both operating and capital costs for existing and future gas processing plants as well as a decrease in corrosion rates with prolonged plant life.
Lessons & Concerns from Experiences in Conception, Design and Constructions of Deep Wells in the Niger Delta Basin of Nigeria
Authors: Pedro Abiye Iyalla , Odiete Raphael
Published: July 2017

The experiences garnered in drilling deep wells in the Nigeria Delta Basin of Nigeria are presented herein. The referenced wells were drilled to the deep target series of gas and gas condensate reservoirs at depth range of 4900m – 5530m. The total volumes of the targeted reservoirs are about 60mmstb of oil and 1400bscf of gas.

There were challenges of stuck pipes in phases through some depleted zones/reservoirs that were resolved through brainstorming with the production unit of the company. Other challenges encountered and highlighted are in hole stability, bit selection, Well control, HSE, rig efficiency and cost performance. Drilling the wells in sequence exploits the benefits of immediate application of gathered experiences from the previous wells.

This paper presents the key challenges associated with the drilling of deep wells as experienced in the referenced wells.
Crude Oil and Associated Production Optimization: A Case Study of X Field in Nigeria's Niger Delta Region
Authors: Okafor Emeka , Kalagbor Christian
Published: July 2017

Almost always crude oil is produced in conjunction with associated gas and for the type of reservoir considered in this study, gas production rate over time increases with decreasing pressure. The problem of maimizing production and/or recovery can be addressed by adopting an innovative, multi-stage separation technique. We use theoretical analysis and the latest version of Aspen HYSYS to demonstrate process plant optimization of a real case study of a separation facility in Nigeria's Niger Delta area with the objective to achieve higher plant profitability than those achieved by current practice. Based on the estimation of the optimum separator pressures for a 48,470 bbl/day crude oil and 50.27 MMSCFD gas production facility, it is found that crude oil and associated gas recovery increased by 1,620-bbl/day and 0.21 MMSCFD, respectively. Compared to current practice at the facility, a yearly average of fourteen million US dollars would be realized by our improved multi-stage separation method.
Reliable SCAL Data for Reservoir Modeling: Case Study of a Niger Delta Reservoir
Authors: Wobo Monica A. , Onyekonwu Mike O.
Published: July 2017

Special Core Analysis (SCAL) data has a direct impact on the way fluids are allocated and distributed in the reservoir and simulation models, which would directly impact reservoirs' STOIIP estimation and their distribution. Moreover, it directly affects the performance of secondary and EOR flooding processes, and in turn impacts the accuracy of the oil and gas reserve estimates, and the management of these reserves. Therefore, SCAL data could be considered as one of the most critical reservoir input data for reservoir simulation models.

This paper shows how a reliable SCAL data was used for Reservoir Modeling workflow and it's impacts on the accuracy of the oil and gas reserve estimates results of integrated reservoir studies performed on XX reservoir of an onshore field in Niger Delta. The studies include petrophysical analysis, static reservoir models and building Numerical models.

This Paper sheds light on the theoretical and experimental background of SCAL data. It explains the concept of reservoir wettability and different factors that could induce changes in reservoir wettability. Further, the concept of capillary pressure and its associated hysteresis for different wettability conditions were considered. The concepts of two phase water/oil and gas/oil relative permeability curves and how to generate three relative permeability data for water wet, mixed and oil wet reservoirs were demonstrated. It clarifies the saturation end point of both capillary pressure and relative curves as a function of reservoir heterogeneity and wettability, the idea of reservoir wettability profile.
Prospects of EOR Using CO2 in Reservoirs of the Niger Delta
Authors: Ogolo Naomi Amoni , Wobo Monica Aleruchi , Onyekonwu Mike O.
Published: July 2017

Enhanced oil recovery (EOR) using carbon dioxide (CO2) has proved to be successful in some oil producing regions of the world, but this method has not been implemented yet in the Niger Delta. Crude oil swells when mixed with CO2; this makes the oil light and causes it to flow more easily within the reservoir. This work thus investigates the prospect of using CO2 for EOR in the Niger delta by simulating the outcome with three depleted reservoirs in the region under full water drive, partial water drive and volumetric drive mechanisms. The reservoirs were produced until production was no longer economical, necessitating external support. The life of each reservoir was extended for a production period of twenty years after its economic life under four simulated scenarios. The first was continuous production from each reservoir under the natural drive mechanism to serve as the reference case. The second scenario involved water injection while the third entailed injecting CO2 into each reservoir for twenty years. The fourth method was still CO2 injection but with intermittent water injection; the water alternating gas (WAG) method.

Very significant improvement in terms of oil recovery factor was observed with the reservoir under partial water drive and fluid expansion mechanisms. The reference, water injection, CO2injection and CO2 WAG scenarios for the reservoir under partial water drive mechanism yielded 40%, 63%, 56% and 65% respectively. For the reservoir under volumetric depletion, the reference, water injection, CO2injection and CO2WAG had 33%, 63%, 58% and 61% respectively. There was also improvement for the reservoir under full water drive mechanism with the use of CO2 but it was not very significant probably because full water drive mechanism for oil recovery is efficient and would have effectively swept the reservoir of its recoverable oil.
Best Practice for Marginal Oil Field Development and Production Sustainability beyond First Oil Production. – Niger Delta Case
Authors: Oyakhire Basil , Omeke James
Published: July 2017

More than 13 years after the award of 24 marginal fields and subsequent award of a total of 30 marginal fields by the Federal Government of Nigeria, only 30% of the operators/farmee have being able to achieve first oil and sustained production for more than one year. An equivalent of 58% have achieved first oil.

Since the award, these operators and farmee have encountered various financial and technical challenges in bringing their fields to first oil.

This paper is an outcome of years of experience working with marginal field operators in the development and management phase of their fields in Nigeria. The discussion in this paper will cover field development planning – from modelling to economics and reservoir management strategies directed from case experiences. It outlines major technical challenges faced by marginal field operators in developing their fields and proffers effective and pragmatic solutions based on best practices in the oil and gas industry to help minimize some uncertainties associated with the field development, optimize allocation of resources, achieve first oil and ultimately, increase production life of the field through sound reservoir management strategies.
Applications of the Normalized Pore Throat Radius Methodology for Improved Hydraulic Flow Unit Characterization Using the Niger Delta Field as Case Study
Authors: Onuh Haruna Monday , OgbeDavid David
Published: July 2017

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 (Rtot¯) methodology for improved hydraulic flow units characterization and production optimization in complex reservoir systems. A modification of the reservoir quality indicator (RQI), Stratigraphic Modified Lorenz Plot (SMLP) and Leverett J-Function methodologies for hydraulic flow unit characterization using the Rtot¯ concept demonstrates improved calculation of hydraulic flow units using dataset from the Niger Delta deep water turbiditic system.

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 Rtot¯ model for hydraulic flow zone characterization.
The Possibility of High Recovery from a Naturally Depleted Oil Reservoir
Authors: Ibe Mmakwe , Elias Arochukwu , Igali Iyegoe , Emeka Ezeike , Akwaowo Otung , Manson Egberibine
Published: July 2017

Recoveries beyond 70 % from naturally depleted oil reservoirs usually pose some concerns and suspicions regarding the in-place volumes and possible production allocation issues. These concerns are strongly influenced by a view that such recoveries are not common in most basins of the world. The impact of this perception is a restriction of further developmental activities and some subtle pessimism in reserves estimation on the culprit reservoir(s). It also results in a series of reviews aimed at justifying or nullifying the current reality - the latter of which is preferred. This work details the result of an inquiry into this possibility from the perspective of both the dynamics of oil recovery and real field cases from the Niger Delta basin.

Three approaches were adopted to resolve this inquiry. The first explored global benchmarks in order to gain insights on what has been observed globally. The second established from past studies the prevailing factors that govern recovery and to understand practices and natural circumstances that influence these factors. Finally, real cases of naturally depleted water driven reservoirs were considered with a view to highlight the key factors at play in the performance of these reservoirs.

The results were consistent and showed that globally recoveries above 70% are possible. It has also been further established that recovery factors are largely influenced by 4 efficiencies namely - microscopic sweep efficiency, macroscopic sweep efficiency, connected volume factor and economic efficiency factor. These efficiencies are always at play in all reservoirs and a consistently high value in all of them will correspond to a high recovery. A minimum of 93% in each of them (if all values were equal) or at least 70 % in one (the other efficiencies are 100%) guarantees high recovery. In all the field cases where high recovery factors were observed, high values can be attributed to each of these efficiencies.

The study concludes that recovery beyond 70 % is possible from natural depletion in oil reservoirs under water drive. In such reservoirs, further development including Short Term Oil Generation activities should not be discouraged even as resulting cumulative RF may seem higher than commonly encountered values. It is critical for the achievement of high recovery from new developments to focus on the controllable factors that influence recovery when designing such projects.
Economic Optimization of Water and Gas Shut-Off Treatment in Oil Wells
Authors: Egba Amba Ndoma , Ajienka Joseph A. , Iledare Omowumi O.
Published: July 2017

It is estimated that on the average, three barrels of water are produced for every barrel of oil. Billions of Dollars are spent each year in treating unwanted water and gas production in oil wells. Water and Gas Shut-Off (WGSO) treatment has helped to reduce cost and improve oil recovery in some cases, while in others, this method has failed to economically recover the remaining oil in the reservoir. Economics drives the oil and gas business because the objective is to take decision that will reduce cost and maximize profit. Any decision that is made without this consideration, may be an exercise in futility. Therefore, detailed economic evaluation as a diagnostic tool for WGSO treatment has become imperative.

Despite the technical appeal, WGSO schemes can also be related to games of chance. Company has to decide whether to risk the money or not since it is not certain whether there will be a simultaneous increase oil and decrease in water/gas production. There is absolutely no 100% guarantee of success because the justification for the selection of any WGSO treatment method will be based on the probable incremental hydrocarbon production. Some water and gas control treatment can guarantee substantial production increase while others could be less successful. This introduces some degree of uncertainty, making WGSO treatment a risky venture. So, the quantification of risk and uncertainty is necessary.

Though the optimal decisions in water and gas shut off application differ from company to company, the objective however is to obtain a condition under which the marginal and total revenue from water shut off will be equal to the marginal and total cost of the operation. To Optimize WGSO application in oil wells, we must determine the production rate that maximizes its total profits.

Against this backdrop therefore, an economic model is developed that is used to evaluate water and gas shut-off candidates. This model incorporates Monte Carlo simulation and risk analysis on different reservoir parameters, incremental recovery and oil price to optimize WGSO applications. It allows for the determination of the probability distribution function for the different economic indicators that will help in ranking WGSO opportunities.
Evaluation of Polymeric Water and Gas Shut-Off Treatments in Oil Wells
Authors: Egba Amba Ndoma , Ajienka Joseph A.
Published: July 2017

Controlling excessive gas and water production from oil wells is still a major problem in the global E & P industry. Various strategies have been advised in the petroleum literature by industry experts and vendors. Different service companies continue to lay claim of innovative Water and Gas Shut-Off (WGSO) products that will offer better results. No doubt, there are noteworthy improvements in unwanted water and gas control technology, the problem however, has continued unabated.

Polymers have been developed to help in the reduction of the water-oil-ratio (WOR) while at the same time not limiting the flow of hydrocarbon. Polymer-foam for gas shut off also reduces the GOR, but not the oil flow rate. Though, some successes have been reported in polymer water and gas shut off in oil wells, a survey of field cases however shows, that most treatments have been unsuccessful. Our findings suggest that different diagnostic methods, treatment design and applications vary from vendor to vendor even with the same diagnostics. Companies also use different economic yardsticks to measure the success of WGSO operation. This has led to tremendous failures in polymeric WGSO application.

Relying on a data base of WGSO field cases, some treatments could guarantee substantial increase in oil production while in others the production was relatively small, zero and sometimes negative. Several factors could be responsible for these; Wrong diagnosis and poor candidate selection, improper treatment design and application. There is also lack of an economic model to evaluate the success of a polymer water and gas shut off treatment.

This paper therefore evaluates the causes of success or failure of the polymer water and gas shutoff treatment in the Niger Delta
Multirate Welltest Design - Niger Delta Field Experience
Authors: Ndukwe Reginald , Umoh Magdalene , Adepoju Yaqub
Published: July 2017

Multirate welltests are conducted to determine well deliverability, skin and distance to major fault boundary; as well as reservoir data like permeability and pressure. A reservoir was planned for development with four wells to supply about 500 MMscf/d of gas to a primary treatment facility.

The proposed wells were designed for multirate welltests to boost confidence on meeting the gas supply obligation. The multirate welltest program includes (1) Initial Build Up, (2) Flowing, (3) Final Build Up and (4) Static Survey periods. The test design determines optimal duration for each activity in the program; to ensure the test objectives are achieved. This paper shares results of the test designs for the wells and insights gained from the exercise.

The results show that wells close to boundary fault (less than 250 m gap) were not good candidates for final build up survey as the fault signal appears early (within 0.1 hr survey time) as boundary effect; thereby overlapping with wellbore storage effect phase and masking infinite acting radial flow period (used for estimating well and reservoir parameters). Hence, final build up was not proposed in such wells. Those parameters can be estimated from other wells in the same reservoir. Sensitivities were done by varying the reservoir structure, permeability, well skin and wellbore storage effect.

Test design results also show that infinite acting radial flow period signal was observed within 0.1 to 2 hrs of final build up; followed by fault boundary response visible from 2 to 24 hrs. It can be concluded that final build up survey period of 10 hours is optimal to meet the test objectives.
Standardized Well Design Driving Project Delivery in an Offshore Brown Field
Authors: Ademide Adegbite , Rukayya Dabana , Abisola Kuku , Ejiro Ogbodu , Aihanuwa Ukponmwan
Published: July 2017

In the current ‘lower for longer’ oil price environment, there is a need to ensure sustained delivery of wells at competitive costs without compromising safety and well integrity. Well operations in a brown field give unique opportunities to harness the advantages presented by knowledge of the field as well as the quantity and quality of subsurface and operational data available. One of such advantages is the opportunity for standardizing the well design for the field.

This paper describes the journey to arriving at a standardized well design in the Bonga field, the subsequent contribution to efficient delivery of projects and the challenges experienced in its application. Standardizing the well design has significantly reduced the need to ‘reinvent the wheel’ in the opportunity maturation process as detailed front end loading can then be carried out field-wise with iterations done for specific wells as required. Execution of operations on the field has witnessed continuous improvement as operations are usually batched and kept consistent across wells. With materials requirements clearly defined, significant savings are achievable through longer term contracts and effective management of the materials inventory.

The application of a standardized design is not without some associated challenges, regrets and potential blind spots. Proactive identification, evaluation and knowledge of these challenges were required to ensure that they were effectively managed. Details on how some of these challenges were managed as well as results from the application of the standardized well design philosophy in the Bonga field are provided in this paper.