bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparative Analysis of Drilling Cost Used for Petroleum Economics in the North Sea, Gulf of Mexico and Niger Delta Regions
Authors: Ikwan Ukauku , Egba Amba Ndoma , Dosunmu Adewale , Iledare Wumi 
Published: July 2016

Abstract
The primary objective of an E & P company is to drill and produce hydrocarbon at minimum cost with high level of safety without compromising environmental standards. With the current global downward slide in oil prices most E & P firms are slashing costs to shore up profitability. Drilling operations are high capital-intensive projects that drive unit production cost northwards. This paper presents a comparative analysis of drilling costs in three geographical locations of the world petroleum provinces viz; North Sea, Gulf of Mexico and Niger Delta with sensitivities of the various elements that affect drilling cost with a view to assisting operators and rig owners on optimizing activities in a lean environment.
Relying on panel data sourced from databases of a global energy consultant and industry operators, historical absolute average cost and footage trends were compared during the period of 10 years (2005-2014). A randomly selected well cost data was used to carry out the sensitivity analysis to deduce key determinants.
It was found that although there are regional differences that reflect the local geology and some economic factors, drilling times and all costs rise sharply with increasing depth. Also drilling cost for the Niger delta province is highest compared to the other two regions. The sensitivity study showed that the highest contributor to high drilling cost is the intangible element in which the rig rate, hole problems and security issues should be the focus in drilling cost reduction and economics. Contract renegotiation strategy to drive down rig rates and establish new market equilibrium is recommended in this lean environment. Also tangible costs from tubulars can be reduced with favourable policy on reviving Nigerian steel industries to enable local sourcing of these tubulars, improve employment rate hence reduce insecurity in the Niger Delta area.
Gas to Power in Nigeria: This Burden on Natural Gas
Authors: Onwuka Emmanuel I. , Iledare Omowumi O. , Echendu Joseph C. 
Published: July 2016

Abstract
One million heads of population require at least 1000 megawatts of electricity capacity as a rule of thumb in industrialized economies. Sub-Saharan Africa (SSA) as at 2013 averaged about 0.91 MW per one thousand head of population on this scale. Nigeria is the largest economy in this region, but only attained peak generated power of 5074.7 MW in 2016 giving it a generated power per population (GPP) value of 0.003%. Nigerian economic development is stunted by the perennial abysmal performance on the scale of GPP.
Many studies have reported a seemingly direct proportionality relationship between economic development and available electricity capacity in a clime. Nigeria has plans to increase electricity capacity through natural gas utilization. This energy resource sustainability however, may not be guaranteed from a non-renewable scale.
This paper evaluates the sustainability of electricity capacity targets in Nigeria and the need placed on natural gas keeping in perspective 0.1%, 0.0075% and 0.003% levels of GPP.
The approach adopts a gas turbine (GT) performance modelling leveraging on the basic thermodynamic processes. Specific fuel consumption (SFC) is determined from the operating conditions of a GT. Given the set GPP scenarios, power profiles are evaluated by imposing the electricity demand outlook estimated with base population growth rate of 2.52%. Interaction of the SFC and the power profiles result in the required quantity of natural gas supplied to the GT power stations.
Neglecting reserves replacement and assigning 70% of base electricity demand to natural gas, a GPP of 0.1%, 0.0075% and 0.003% would deplete allotted base reserves at estimated yearly average rates of 30.8, 6.25 and 4.41 bcf/d respectively. This may only be sustainable for just 16, 79 and 112 years in that order.
It is therefore instructive that renewable electricity generation sources be reconsidered in the future energy resource mix projections for genuine economic development in Nigeria.
Efficient Installation of a Modular Straddle System for Deep Water Gas or Water Shut Offs
Authors: Rajamani Karthik , Ipsen Michael 
Published: July 2016

Abstract
A well with a high gas-oil-ratio (GOR) was experiencing gas coning due to the recycling of injected gas. A gas shut off was recommended to improve gas handling efficiency due to the constraints on surface processing capacity. The strategy was to install a 138 m, retrievable straddle assembly across a zone spanning from 2572 m measured depth (MD) to 2719 m MD in the 5 ½" open hole gravel pack (OHGP) screens.
The client's considerations included coiled tubing (CT) and slickline. It was also necessary to be as efficient as possible to keep time and costs down. Based on these considerations, the operator decided to use an electric line (e-line) tractor combined with a hydraulic stroking tool for its high reliability. The stroking tool also provided the benefit of delivering the required force at the exact point where it was needed downhole as compared to coiled tubing, which would exert the force from the surface.
The complete straddle packer assembly was successfully installed in 17 runs without any non-productive or lost time incidents. As a result of the intervention, gas production was greatly reduced and oil production was returned to normal levels. The operation was so successful that the client saved nearly 30 days on an operation that was planned for 45 days.
Due to the success of the initial operation, the client decided to execute several other, similar water and gas shut off operations in the field replicating the same methodology. This paper highlights the methodology used and the cost and HSE benefits provided by selecting the e-line solution with the tractor and stroking tools to perform the gas shut off. The paper will also discuss the details of the job planning as well as the execution of the operation, marking a first in this West African country.
Impact of Oil Base Mud Contamination OBM on Waxy Crude Properties
Authors: Mmata Bella , Ajienka Joseph , Onyekonwu Mike , Chukwu Godwin 
Published: July 2016

Abstract
Oil base drilling mud is commonly used during drilling operations because of the associated advantages especially in terms of cost and time savings benefits. However, once there is excessive overbalance pressure in the mud column during drilling, the oil base mud will invade the hydrocarbon formation. And since base oil used in preparing the drilling fluid is miscible with the formation hydrocarbon fluid, it will contaminate the reservoir fluids and alter the fluid's properties. Hence for waxy fluids (paraffinic), when early time contaminated samples are collected down hole via open hole wire line sampling, erroneous fluid property data will be generated in the course of characterization. Such erroneous data can be quite misleading, especially when used for the early phase upstream facility design. And the cost implication can be enormous for the flow assurance engineer. In this work, a waxy crude sample was collected from an onshore field in the Niger Delta region. Subsequently, the sample was contaminated with various levels of oil base mud in order to investigate the errors induced by OBM on waxy crude properties such as the wax appearance temperature (WAT), pour point, density and viscosity. The result shows that the presence of OBM contamination, significantly impacts on the waxy crude properties with pour point temperature being the most affected by contamination. Hence caution should be exercised when using or interpreting experimental data obtained from waxy samples contaminated with oil base mud.
Process Design Evaluation of an Optimum Modular Topping Refinery for Nigeria Crude Oil Using HYSYS Software
Authors: Mamudu O. A. , Igwe G. J. , Okonkwo E. 
Published: July 2016

Abstract
Industrially, unprocessed crude oil has little or no value; hence there is the need for any country to have operational petroleum refineries to convert the crude oil from its original state into more useful product. According to the Nigerian National Petroleum Corporation (NNPC) 2001-2013 annual bulletin, even with a total refining capacity of 445,000 bopd (barrel of oil per day) expected from the Nigeria four conventional refineries, the country still records scarcity of refined products as none of the refineries can boast of working above 60 percent of its design capacity. In an attempt to provide solution to the above worsening scenario, modular refineries set up at strategic positions within the country can help to boast refining capacity. Although different modular topping refinery configurations exist, this paper examines the simple, pre-flash and the pre-flash pump around reflux scheme in terms of maximum product yield using the Niger Delta Petroleum Resources (NDPR), Bonny Light, Bonny Medium, Brass and Qua Iboe crude assay. Crude oil characterization using Aspen Hysys was done based on their true boiling point to determine the maximum liquid volume fraction of the different distillates. Simulations of the different crude assay were carried out on the different topping refinery configurations highlighting the variation between characterized and simulated volumetric cuts. The result shows that NDPR crude will favour the production of LPG, light naphtha and diesel. Bonny medium crude will favour the production of gas oil and residue oil while qua iboe and brass will favour the production of kerosene and heavy naphtha respectively. The best scheme for different distillates was also determined
Evaluating the Relationship Between Natural Gas Hydrocarbon Heavy-Ends Condensation and Its Hydrocarbon Dew Point HDP
Authors: Ibemere Uche , Mmata Bella , Onyekonwu Mike 
Published: July 2016

Abstract
Natural gas comprises of non-hydrocarbons, light and heavy-end hydrocarbons. Although heavy-end hydrocarbons, may be present in negligible concentration in dry or lean gas, its reasonable occurrence in wet or rich gas is of great concern to all stakeholders because of their ability to retrograde and coalesce into liquid or solids.
Hydrocarbon Dew Point is basically controlled by the availability and quantityof condensable heavy-end hydrocarbons in a natural gas sample. In this work, fifteen natural gas samples, collected from different flow stations and gas processing plants in the Niger Delta Region were used. In this exercise, efforts were made to establish the relationship between the liquid content of the gas or condensable hydrocarbon and the resultant measurable hydrocarbon dew point of the same natural gas sample.
The natural gas samples were analyzed by Gas Chromatographic technique in reference to ASTM D1945 (2013). The results generated were reported in gallons per thousand cubic feet (GPM) of various alkane plus fractions. HDP was measured with manual dew-scope, using ASTM D1142 as standard method. NIST 1297 and Statistical tools were used to quality-check generated analytical results.
The results of this work confirmed that there is a relationship between condensable hydrocarbons and practical hydrocarbon dew point. It also highlighted the need to employ gas chromatographic method as a tool to give a vivid picture of the condensable heavies that resulted in the measured HDP.
Evaluation of the Impact of Inter-Reservoir Communication on Resource Volume via Material Balance Multi Tank Model
Authors: Mogbolu Emmanuel , Okereke Onyedikachi , Olatope Victor , Onobrudu Portia , Olubamise Taiwo , Ukauku Ikwan 
Published: July 2016

Abstract
A multi-tank model is presented that was used to evaluate the volume of gas produced from an undeveloped gas reservoir as a result of sand-to-sand juxtaposition with a developed oil rim reservoir. An innovative approach of using Microsoft Excel via OpenServer to link MBAL model to history match reservoir pressures in a multi-tank model, while considering all the reservoir uncertainties was adopted. The process helps to save time in Reservoir Management.
An oil rim reservoir with future gas development seemed to be communicating with an undeveloped gas reservoir via sand to sand juxtaposition based on the pressure data taken during the drilling of one of the wells and fault seal analysis. This clearly showed depletion in the undeveloped gas reservoir.
Through a multidisciplinary approach, the two reservoirs were built into tank models and connected using a transmissibility model. The resultant model was history matched using an experimental design approach and contacts calibrated prior to running simulation and prediction.
The result showed the quantity of Gas Initially in Place (GIIP) in the undeveloped reservoir that has flowed into the developed reservoir and has possibly been produced already. This insight provides a quick analytical understanding on the resource volume impact of this phenomenon on both reservoirs with respect to their future gas development. This has led to the need for a revised development plan for both reservoirs with respect to future gas production.
The novelty of the use of experimental design with MBAL multi-tank model in this scenario is in the ability to history match the model in reasonable time. This is achieved while effectively managing reservoir uncertainties. This is critical for key business decisions on reserves booking, business planning, general reservoir management and production.
Curing Lost Circulation with an Engineered Spacer During Cement Placement
Authors: Mofunlewi Samuel S. , Okoto Francis 
Published: July 2016

Abstract
One of the arts of providing zonal isolation in wells is the ability of the cement to fully replace the mud system in the annulus. One way of achieving this is to pump a spacer system that can displace the mud, which means the spacer system should be able to generate enough downhole force to overcome the yield stress of the mud. To achieve effective zonal isolation, the cement spacer must remove both movable and immovable mud (that may have gelled up during static conditions) from the wellbore before cementing. To achieve this, the mud must be conditioned through circulation so that the rheological properties of the mud in and out of the well are uniform.
Challenges are usually encountered in wells where losses are experienced during drilling or while running casing. Usually, attempts are made to cure such losses before the cement job. Unfortunately, some losses cannot be cured with lost-circulation materials before the cementing operations. When such situations arise, it becomes difficult to condition the mud or circulate the mud to alter the rheological properties, as circulation can result in further break down of the formation, thereby leading to more severe losses.
A similar challenge occurred during operations for an operator in Kenya. After drilling the well to the expected total depth, during the casing run at a flow rate of 150 gpm, total losses were observed. To solve this problem, an engineered cement spacer that can cure moderate to total losses was deployed during the cementing operation. This unique spacer system can form a seal across the sand face and can be designed with rheological properties optimized to enhance the displacement of unconditioned mud.
This paper will describe in detail the unique nature of this cement spacer in curing losses as well as the mechanism with which it provides its sealing effect in permeable and fractured formations. Case studies will be presented to describe how the spacer has been used to cure moderate to total losses in oil, gas, and geothermal wells in formations with low fracture gradients and induced fractures.
A Review Study of Oil Displacement Mechanisms and Challenges of Nanoparticle Enhanced Oil Recovery
Authors: Idogun Akpevwe Kelvin , Iyagba Elijah Tamuno , Ukwotije-Ikwut Rowland Peter , Aseminaso Abiye 
Published: July 2016

Abstract
The utilization of nanoparticles (NPs) as an agent for improved oil recovery (IOR) and enhanced oil recovery (EOR) has attracted a lot of attention over the past decade. NPs are known to have high mechanical and thermal stability and they can be tailored to meet the specifications of a given reservoir system. As a result, as opposed to polymers, NPs are suitable options for EOR processes as they are capable of withstanding high temperatures, pressures, shear and salinity in harsh environments often prevalent in subsurface oil reservoir systems. Researchers have made promising observations and results at laboratory scale, proving that nanoparticles possess the capacity and potential to reduce residual oil in the rock matrix thus increasing ultimate recovery. NPs have been observed to lower interfacial tension (IFT), reduce the viscosity of oil and alter wettability. This study presents an in-depth review of the oil displacement mechanisms that favour nanoparticle enhanced residual oil recovery. It goes on to review the causes and effects of NP retention in porous media. Processes carried out at laboratory scale and properly designed for reservoir fluids may fail when implemented at reservoir scale as a result of geological factors. Hence the review concludes by making recommendations for successful NP EOR projects.
Spontaneous Imbibition in Niger Delta Cores
Authors: Kerunwa A. , Onyekonwu M. O. , Anyadiegwu C. I. , Olafuyi A. O. 
Published: July 2016

Abstract
Spontaneous imbibition is a process where the non-wetting fluid is displaced by the wetting fluid in a porous medium by means of capillary forces. Spontaneous imbibition plays a key role in oil recovery.
This paper presents experimental data for countercurrent spontaneous imbibition into cores with different porosity and permeability. Experiments were performed using Niger Delta sandstone core samples. Core samples were initially saturated with brine. Crude oil samples of different viscosities were then injected into the core samples. Synthetic reservoir brine was used as the wetting phase.
Scaling the experimental data of spontaneous imbibition with different injection fluids is crucial to properly design improved recovery methods and to predict their performances. In this work an analytical solution of a model describing counter-current imbibition was derived. Recovery curves were used for scaling the data in different cores and at different interfacial tensions. The scaling approach developed by Li and Horne yielded satisfactory correlation for all the cases. The results obtained were compared with the model we developed which also correlated satisfactorily. We also used the solutions of the model we developed to gain insight into the parameters that control oil recovery by spontaneous imbibition.
Effect of N-Vinylcaprolactam on Hydrate Inhibition in Gas Dominated System
Authors: Odutola Toyin Olabisi , Onyekonwu Mike Obi , Ikiensikimama Sunday Sunday 
Published: July 2016

Abstract
Sub-sea developments produce greater flow assurance and intervention challenges. Low seawater temperature may lead to hydrate formation in subsea pipelines. The effect of N-Vinylcaprolactam in preventing hydrate plug formation in gas dominated systems was studied using a 12 meter long closed loop designed for hydrate studies. The experiments were conducted by circulating gas and water at 150psi in the presence of 0.04wt% or 0.05wt% concentration of N-Vinylcaprolactam. The equivalent weight of N-Vinylcaprolactam used wasobtained based on the weight of water fed into the loop. Results showed that the loop pressure declined to 105 psi when 0.05wt% N-Vinylcaprolactam was used as inhibitor. However, when 0.04wt% of N-Vinylcaprolactam was used in the constant volume experiment, the loop pressure decline to 83psi implying that more gas was used up in forming hydrates. In the uninhibited system, the pressure declined from 150psi to 70psi and hydrate plug was noticed. This implies that at 150psi, 0.05wt% concentration of N-Vinylcaprolactam was effective at preventing hydrate formation in the experimental hydrate loop. Mathematical models describing the performance of N-VCap in the experimental loop were derived from experiments conducted. Hydrates may form in subsea pipelines in the presence of inhibitors if the appropriate dosage is not used. It is therefore important for the engineer to evaluate the effective inhibitor dosage prior to field implementation.
Model to Predict the Viscosity of Waxy Crude oil
Authors: Ketebu Promise E. , Ajienka Joseph J. , Ogbonna Joel , Ikiensikimama S. Sunday , Ukwu Austin K. 
Published: July 2016

Abstract
Waxy Crude Oils deposit wax at temperatures below the wax appearance temperature (WAT), thus exhibiting non-Newtonian flow behavior. In this study, the viscosity of waxy crude oils from 20 oil fields in the Niger Delta were measured for temperatures above and below the WAT using the Cannon-Fenske viscometer in line with D445 procedure on 112 viscosity data points. Of these total data points, 100 were used to develop the models and 12 were used to validate and compare the developed correlation with other correlations. Models for waxy crude oil viscosity and wax appearance temperature were developed using multiple regression analysis. The input data to the models are pour-point determined in line with ASTM D97, API obtained with ASTM E126-76 methods. The developed viscosity and WAT models have average deviations of 5.83% and 2.48% respectively.
Benefits of Robust Data Integration in Gas Cap Blow Down Phenomenon - Reservoir Life Cycle Resource Estimation Case Study
Authors: Dennar Linda , Emelle Chima , Bakare Olatunji , Etuk Ubong , Daodu Olugbenga , Ahmed Suleiman , Nwachinemere Uche , Obeahon Percy , Ukauku Ikwan , Mafe Oluwaseun 
Published: July 2016

Abstract
This paper provides an insight into the gains and realism injected into life cycle resource estimation of a gas cap reservoir slated for gas cap blown in 2030. Proper data integration spanning from subsurface to surface cannot be over emphasized as the major trigger for the successful estimation of the life cycle resource in this reservoir alongside a realistic execution time line for the gas cap blow down project.
One major consideration in the evaluation of gas cap blowdown projects is the efficient and maximal recovery of the oil rim available and the subsequent prediction of the gas cap blow down on stream phase while complying with statutory promises. A major enabler to achieving this objective in the ZN reservoir was the ability to harness and integrate available shared critical data from the subsurface, production, studies team, forecasting team, facilities and concept engineering teams in a pragmatic and cost effectively manner.
The ZN is the largest gas cap reservoir in the X-Onshore field. Current STOIIP is 320MMstb and GIIP is 1.4 TCF. The reservoir started production 21 years ago and a total of 13 oil wells have produced from this reservoir with two gas wells proposed to be used in the blow down of the gas cap at a future date. Cumulative oil production so far is 46MMSTB and 157BSCF AG which translates into a current oil RF of 14%.
Accurate estimation of the Gas Cap Manifold Inlet Pressure, the Gas Cap blow down on stream dates and project prioritization were key factors required for the proper prediction of the life cycle resource for this reservoir.
This paper seeks to describe how effective the process of proper data integration has been in assisting the delivery process that has translated into a more realistic and robust gas cap blow down time line and resource evaluation that synergizes with the stakeholders growth aspirations.