bluuebunny/crossref_metadata_2025_split huggingface dataset:
Initial Production Rate Estimation: Impact on Recovery and Interplay of Recovery Process
Authors: Olufemi Adebayo , Ambastha Anil 
Published: July 2017

Abstract
One of the many processes utilized by subsurface teams to grow / sustain production is infill drilling. The choice of whether an infill opportunity will be drilled is finalized with detailed economic evaluation after all subsurface assessments have been completed. The economics of a proposed infill opportunity is mainly impacted by cost and recovery. Recovery is a function of initial production (IP) rate and length of plateau (sustained) production at the IP.
This paper explores key considerations in the selection / determination of initial production (IP) rate for forecasting recovery from infill wells. Using history-matched simulation models, rate sensitivity analysis was carried out for each well per subsurface model realization (P10-50-90) of the reservoir of interest. IP rates were then selected to ensure that they gave optimum incremental recovery for each subsurface model realization without compromising the commercial viability of the opportunity.
The approach described in this paper not only provides a robust way of estimating IP rates, but also gives insights to (i) better understand the interaction between the IP rate and the recovery process and (ii) identify potential upside if the "best case" scenario is encountered when a well is drilled. This paper also poses questions around a need for an industry-standard methodology to signpost, measure and report IP rates after well start-up.
Comprehensive History Match and Forecast Work for an Oil Reservoir with Uncertainty in Original Gas Oil Contact
Authors: Okpani Olu , Ambastha Anil 
Published: July 2017

Abstract
A comprehensive reservoir simulation study was recently carried out for the A4 reservoir located in the Niger Delta. The A4 reservoir is divided into two fault blocks (Main and West) that are connected in the down-dip part of the reservoir both in the oil leg and aquifer. Original Oil-Water Contact (OOWC) was logged in the reservoir, but no Original Gas-Oil Contact (OGOC) was logged by the wells that penetrated the reservoir. Thus, there existed uncertainty in the OGOC from the Highest Known Oil (HKO) to the crest of the reservoir.
During the period of the simulation project, two oil producers (A4-1p and A4-2p) were producing from the Main Block, while one water injector (A4-1i) was providing pressure support. Two additional oil producers were then being planned to increase the recovery from the reservoir. One of the wells was planned to be drilled up-dip of the existing two producers in the Main Block, while the other well was planned to drain the West Block.
Base model deterministic history-match and sensitivity studies were conducted to gain insight into the reservoir performance and parameters that affect history match, especially the OGOC. Then, probabilistic history-matching was carried out to assess the full range of uncertainties of the different history-match parameters with special consideration to the OGOC.
Probabilistic history-matching shows that the P10 OGOC for the Main Block is about 24ft shallower than the HKO, which was also supported by the base deterministic model. The simulation models were then used to forecast the performance of the two additional planned development wells to validate the planned landing depth of the completions. The two additional development wells were drilled and brought online. Initial test results from the new development wells were consistent with the pre-drill base deterministic simulation predictions.
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.