bluuebunny/crossref_metadata_2025_split huggingface dataset:
From Design to Operate Phase: Sand Control and High Rate Turbidite Well Performance
Authors: Okoh Ehimhen , Oluseye Ogunsina , Green Allen 
Published: July 2011

Abstract
Sand and other solids entrained in reservoir fluids can cause a wide variety of problems in wells and topsides processing facilities1. Sand control is required whenever evidence suggests that unmanageable sand production will occur; typically soon after a well is put on stream for unconsolidated sandstones. The main challenge is to select the most suitable sand control method without compromising well productivity. This paper shares experience from 5 years of production from 18 high rate oil producer wells targeting deepwater unconsolidated turbidite reservoirs in the Bonga field.
The Bonga field, a subsea type development located in ca. 3500ft water depth, has produced over 330 MMstb to date from deviated and horizontal well types, delivering rates as high as 50,000stb/d per well. Seismic and well data show reservoirs are laterally and vertically heterogeneous with reservoir thicknesses ranging from 25ft to over 140ft and average permeability of 1500mD. Thin section, X-ray diffraction and sieve analysis confirm the Bonga sands are generally high quality; well sorted (UC&lt;5), with average grain size ranging between 198 - 260µm, low clay content (&lt; 4 wt %), and limited amount of fines (&lt; 5 wt %).
Three types of downhole sand control methods, namely Frac & Packs, Stand-Alone Screens and External Gravel Packs have been deployed in the field. Critical factors including long-term sand control reliability, cost, well performance, ease of installation, operability and field experience guided the sand control design for the Bonga wells. In some cases real life issues at design and execute phase led to a departure from initial completion and sand control design. To date, actual well performances observed in Bonga are largely dependent on the sand quality (kh), completion quality, filtercake removal effectiveness, well type and sand control type. The dependencies on these parameters are analyzed in detail.
Gas Field Production System Optimization using Coupled Reservoir – Network Simulator and Optimization Framework
Authors: Nwakile M. M. , Schulze-Riegert R. , Trick M. D. 
Published: July 2011

Abstract
Optimization of oil and gas field production systems poses a great challenge to field development due to complex and multiple interactions between various operational design parameters. Conventional analytical methods are capable of finding local optima. They are less applicable for efficiently generating alternative design scenarios in a multi-objective context.
This paper presents an integrated workflow using a simulator coupled to an optimization framework. It is used to investigate the impact of design parameters while considering the physics of the reservoir, wells, and surface facilities. Experimental design methods are used to investigate parameter sensitivities and interactions. Optimization methods are used to find optimal design parameter combinations which improve key performance indicators of the production network system.
The proposed approach is applied to a representative gas production system and is shown to be capable of finding optimal combinations of pipe sizes and compressor power. The method offers a significant advantage over existing conventional techniques.
Geomechanical Modelling of Thermal Effects on Wellbore Stability using the Thermo – Poro – Elastic Model in HPHT Wellbores
Authors: Bassey Akong , Dosunmu Adewale , Lonna Bukola Olaseinde , Stanley Buduka , Sebastine Madu 
Published: July 2011

Abstract
Wellbore stability is a costly problem, and is especially challenging in high pressure, high temperature wells (HPHT) resulting in higher NPT during well operations. Also high pressure high temperature wells are wells whose pore pressure exceeds 0.8psi/ft and at a formation temperature of 400F (150C). Deep and deviated wells are becoming more and more common. One needs to understand the behavior of formation rock in order to control the stability of such wells. The responsible factor is the state of stress, which is influenced by mechanical (in – situ), hydraulic (pore pressure change), and thermal effects. The purpose of this study is to investigate the effect of temperature on wellbore stability under combined conditions (heat transfer with flowing drilling fluid, heat sources generated by mechanical friction, effect of pore pressure on formation temperature profile). Thermal effects at the wellbore wall in the absence of pore fluid diffusion (that is for purely conductive heat flow) can be described to first order using the finite element simulator. Therefore, raising the temperature of the mud leads to an increase in tangential stress, which enhances the likelihood of breakouts and inhibits tensile fracture formation, and on the other hand, cooling the mud inhibits breakouts and which increases the likelihood of development of tensile wall fractures. It is very important that the thermo – poro model is used to predict the zones of instabilities as we drill deep in these wells. The thermal predictions from this model will be used to analyze wellbore temperature during drilling as a function of depth, bit temperatures over the drilling history, cement temperatures from setting to the end of drilling and casing temperatures at selected depths over the drilling history. Also failure to recognized ballooning versus well control is a common mistake made in drilling operations which is one of the leading causes of unnecessary expending casings in narrow margins as a result of high ECD in this wells. The model will be use as a tool in predicting instabilities in this wells and also enhancing effective well construction during well planning for good drilling practices thereby reducing NPT
Hydrocarbon Flow Simulations in Porous and Permeable Media Using Finite Element Analyses and Discrete Fracture Network
Authors: Farayola K. K. , Oluokun M. T. , Adeniyi V. O. , Fakinlede O. A 
Published: July 2011

Abstract
Naturally fractured reservoirs, NFR are distinguished from the conventional reservoirs by the discontinuities in porous media. Prediction of non-Newtonian fluid flow behaviour in NFR is a challenging work in petroleum engineering. Large quantities of hydrocarbons are present in NFR in different regions of the world. The discontinuities in porous media have complicated the description of the petrophysical structures and the fluid flow in fractured porous and permeable media. This study uses discrete fracture network, DFN to explicitly model the flow of fluids through the fractures. In this study, hydrocarbons are treated as non-Newtonian which is the case with waxy or heavy crude oils. Multiphase fluid flow models in porous media are frequently used in many important applications of Earth Sciences, such as in ground water contamination, subsurface remediation and reservoir modeling, Diaz-Vera et al. (2008). The same is true for single-phase flow in porous media. This simulation is carried out using Carreau viscosity model and power law model to describe the relationship between viscosity and shear rate. The simulation is implemented with finite element analysis software, the COMSOL Multiphysics. The results obtained are compared with reference results of Newtonian flow. The influence of viscosity function on the shear rate is weaker in power-law than in Carreau model. Some other characteristic results along with appropriate analysis are presented.
Impact of the Petroleum Industry Bill on Deepwater Economics
Authors: Oyekunle A. A 
Published: July 2011

Abstract
Petroleum has been the mainstay of the Nigerian Economy accounting for over 30% of the GDP and 80% of government revenue. The government with the intention to make the Petroleum Industry generate the kind of economic development it ought to, has sent a Petroleum Industry Bill(PIB) which seeks to restructure the Petroleum Industry to the National Assembly.
The Fiscal Provisions of the PIB gives government a greater access to gross revenue and this consequently has an impact on the economics and profitability of oil and gas investments especially for deepwater which is already very capital intensive.
A fiscal model is developed using an Excel spreadsheet. The spreadsheet is coded by converting the texts of the PIB into mathematics. The fiscal model developed is an integration of the elements of the fiscal provisions of the PIB.
With the investment profile and expected production profile, the model generates a cash flow and profitability indices (PIs) for both investor and government.
Sensitivities are also carried out to establish the relationships between these indices and key decision variables. This understanding of the fiscal instruments would help the IOCs improve profitability.
Results from the model show that royalty rates and the Nigerian Hydrocarbon Tax (NHT) have great impact on company's profitability. However, the sliding scale royalty system of the PIB ensures profitability for both the marginal producer and giant producer. It is also discovered that government surrenders part of its take at low oil prices while its take increases with increase in the price of oil. If IOCs can greatly reduce CAPEX especially those incurred abroad, the fiscal incentives in the PIB and the volume of hydrocarbon contained in deepwater Nigeria would make investment in deepwater remain attractive.
Improved Analytical Model for Predicting Field Production Performance in Vertical Multiphase Flow in Pipes using MATLAB: A Case Study
Authors: Sukubo I. A. , Igboanugo A. C 
Published: July 2011

Abstract
Several multiphase models exist for predicting pressure drops in vertical, inclined and horizontal wells. Most of these models made efforts to unravel the underlying physics of multiphase fluid flow for both mechanistic and analytical models with ranges of applicability. However, these developed models have their specific limitations or ranges of applicability in terms of pressures, rates, basic sediments and water (BSW), choke sizes, fluid ratios, etc thus there is no one model that is universally acclaimed best.
Data from fifteen (15) wells were obtained from a Nigeria field and multivariate linear regression was fitted into the data resulting in a good fit particularly for high production rates/wells. The method of least squares was adopted which involve setting up a set of normal equations, solving them by Gaussian elimination technique and fitting the data into the normal equations. The solution of the primary matrix was obtained through the use of MATLAB software which gave point estimates of the regression parameters leading to the development of multivariate linear regression model. The Bootstrapping method of statistical inference was also used to estimate the confidence interval of these regression parameters, while the Durbin-Watson test statistic was used to test model adequacy. The results of the model compared favourably with existing models within considered range of applicability.
This paper therefore aims to address the challenges of field based multiphase fluid flow model for operational ease using a set of over one thousand production data sets of about forty (40) years of production taken from a renowned field in the Niger Delta. More specifically, our investigations show that taking the infimum (i.e. lower bound) of the parametric bandwidths of the gas rate, average bean size and the model correction factor, b0 the model predictive capability is drastically improved for low to medium rates.
Improving Electrofacies Modeling using Multivariate Analysis Techniques: A Deepwater Turbidite Case Study
Authors: Adoghe L. I. , Aniekwe O. S , Nwosu C. 
Published: July 2011

Abstract
In static and dynamic reservoir modeling, results have shown that the quality and accuracy of the models are dependent on the quality of rock and fluid property inputs e.g. facies, porosity, hydrocarbon saturation, permeability, net sand etc. used in creating the models. Electrofacies (facies defined using electric well logs) are a key property, since most other properties demonstrate some trend with facies.
The typical workflow in modeling electrofacies uses well logs and some type of supervised or hierarchical (unsupervised) technique to cluster/ index the data into a number of groups (electrofacies). The input well logs however tend to ‘correlate’ or ‘anti-correlate’ (sometimes very strongly) and do not truly form a set of ‘independent’ variables that ‘sense’ different attributes of the facies.
This paper presents a statistical technique for identifying and assigning electrofacies using a multivariate analysis technique (Principal Component Analysis (PCA)) to create ‘eigen-variables’ from well logs. These eigen-variables contain all the original information in the well-logs and, in contrast to the well logs, are unique and ‘linearly independent’; therefore resulting in log signatures that are much better used in predicting electrofacies.
We have used this technique to model electrofacies in the Bonga Deepwater field, and the results presented in this paper show a very robust facies network (based on ‘Indexation Phase’ Self-Organizing Maps - SOM) with a higher predictive accuracy than achieved using the well logs directly.
Integrated 3D Modelling in a Structurally Complex Brown Field: A Foundation for Improved Reservoir Management and Optimisation of Further Development
Authors: Sonde Adenike , Omobude Osemoahu , Chudi Obinna , Oghene Ufuoma , Coker Trudy 
Published: July 2011

Abstract
In recent years, numerical reservoir simulation (3-dimensional modelling) has become a very useful optimisation tool, not just for field development planning but also for ongoing reservoir management. Although several analytical methods (such as material balance equations, Buckley-Leverett displacement theory etc) are used as computationally fast and inexpensive tools, they have been recognised as being incapable of capturing the details and complexity of certain reservoirs and processes.
The field presented in this paper is one of the biggest oil fields in the Niger Delta, with an estimated oil in place of over 2.5 billion barrels and cumulative oil production close to 1 billion barrels. About half of this volume and production come from a single reservoir, which is densely faulted. The large number of intra-reservoir faults and the relatively high offtake rates have inhibited the activity of the otherwise strong aquifer and resulted in the high pressure decline observed in this reservoir. Consequently, a lot of the wells quit at relatively low water cuts of 40-50%, with the reservoir pressure being insufficient to lift the crude to surface at higher water cuts.
One of the recommendations of the FDP Update was to increase oil recovery through fieldwide installation of gaslift. However, to quantify the gains of gaslifting and optimize oil recovery through effective reservoir management, an integrated detailed 3D model was required due to the structural complexity of the reservoir. This paper presents the workflow used in constructing, initializing and history-matching the 3D reservoir model; and how the history-matched model was used to assess different development scenarios for improving recovery from this large mature reservoir.
Integration of Mineral Model with Carbon-Oxygen Log Interpretation to Reduce Uncertainty in Hydrocarbon Saturation
Authors: Sinha Ravi Kumar , Kumar Ravi , Pandey Arun 
Published: July 2011

Abstract
Estimation of remaining oil saturation and monitoring the time-lapse changes plays critical roles in hydrocarbon reservoir management. This saturation information is used for tracking reservoir depletion, water-oil contact movement, deciding workover strategies, water-injection/waterflood management and enhanced recovery.
World's most oil reservoirs are in low-salinity environment where Carbon-Oxygen (C/O) logging is invariably used to establish cased-hole oil saturation. The objective of a C/O logging is to locate bypassed or left-over oil reserves and to estimate remaining oil saturation. Mineralogy of the formation significantly influences the C/O log processing for saturation estimation. Quantitative knowledge of formation mineralogy is a key to accurate saturation evaluation form C/O log. Inaccurate lithology information leads to wrong saturation estimation. This uncertainty in saturation calculation can be addressed by including a multi-mineral model generated from traditional petrophysical "elemental analysis" of open-hole logs with C/O measurements.
In cases where a detailed petrophysical analysis is not available for the well, spectral stripping of the capture gamma-ray spectrum, obtained from the C/O log, can define the elemental yields of some characteristic elements. These relative elemental yields are then used in an oxide closure model to derive the dry weight elemental concentration. Ultimately the approach gives a basic mineral model of the matrix in terms of clay, carbonate, anhydrite, coal, evaporite and quartz-feldspar-mica (the sand fraction). This basic model can be used very well in absence of petrophysical elemental analysis to reduce saturation uncertainty.
This paper details a methodology to mitigate uncertainty in saturation estimation due to uncertainty in lithology. Reducing uncertainty is essential for an efficient reservoir management. A suitable mineral model is worth to incorporate in saturation evaluation and can lead to an informed decision making.
Intra-Fault Drilling/Completion in York Gas Field Development: An Economics Improvement Strategy
Authors: Uwaga Anthony , Yan Jun , Jackson Peter , Onafeko Samson , Lukins Paul , Farrow Chris 
Published: July 2011

Abstract
The York gas field is located in the Southern North Sea (SNS) area of the United Kingdom Continental Shelf (UKCS).
Structurally the field is interpreted as having a good number of intra-faults. Of particular interest to this paper is the intra-fault located south-west of the field. Due to the presence of this fault there are two separate crests in the southern area of the field. Each of these two crests was targeted by a horizontal well in the initial development plan of the field. A third horizontal well was to be drilled and completed in the eastern flank of the field.
Recent subsurface studies involving petrophysical, geological and reservoir engineering re-interpretation and analysis carried out in the field confirmed the well count, but not the well type, required for development of the field as compared to previous development plan. Furthermore, it was established that by drilling and completing across the aforementioned south-western intra-fault, instead of avoiding it as done in the previous development plan, the total well count for developing the field is reduced by one.
Two optimal development scenarios, both having similar recoveries, have been identified for the development of the field. Option 1 has two development wells and requires drilling and completing across an intra-fault. Option 2 requires three development wells and no across fault drilling/completion. Economic analysis of the two development options shows that option 1 has better economics indices. Thus, though option 1 is deemed challenging because it requires drilling/completing across a fault the cost savings to be realised from implementing a two well development, instead of the three wells required in option 2, makes it more attractive, nevertheless.
The paper presents the basis and merits of adopting option 1 as the preferred development option for the field. It further discusses the challenges and issues associated with drilling/completing across a fault and way-forward plans to be adopted for a successful implementation of the option 1 development plan.
The paper concludes by presenting option 2 as a contingency option to be implemented in the event that option 1 is not successful with regards to drilling/completing across the aforementioned intra-fault.
Maximizing Profitability and Production Availability through Application of the Principles of the Medium-Term Integrated Activity Planning (MT-IAP)
Authors: Bello Halim , Onabanjo Tajudeen , Godswill Chiorlu , Linda Dennar 
Published: July 2011

Abstract
A smart and robust business plan with clear business goals underpinned by the activity building blocks and the resources to deliver the goals, is recognized as a key requirement for a successful business. In a challenging operating environment like the Niger-Delta however, realizing the business goals requires more than just a good business plan. There are many external factors that could potentially impact the premise upon which the business plan was defined. Some of these include funding, host communities agitation, criminal activities and even local legislations. With the uncertainties that could be posed by any or combination of some of these factors, a process that provides means of re-calibrating the business plan with the new realities to continuously get an early view of the short to medium term impact of the changes is required. In SPDC the Medium-Term IAP process has been deployed to fulfill this need. Additionally the process deploys the Shell global IAP philosophy to drive delivery of the planned activities in an integrated manner, exploring and implementing scope for activities alignment and also checking that resources required for execution of planned activities are sourced timely. This way activities are executed as planned thereby reducing the risk of cost escalations. They are also executed in an integrated manner thereby minimizing shutdown periods and hence production deferment. It also results in cost savings and reduced HSE exposure. This paper describes how this process is implemented in SPDC and highlights some benefits that have been derived from it.
Mitigating the impact of Down-Hole Shut-in Tool Failure on Gas Well Test Data Integrity: UGO -1X Case Study
Authors: Arochukwu EC , Kehinde DA , Aronu GC , Sa'ad Abdul-Wahab 
Published: July 2011

Abstract
This work demonstrates the usefulness of data quality checks for the purpose of achieving test objectives with an example from a Niger Delta well. The well UGO-1X was completed as single-zone single string (SSS) configuration with a 4-1/2 inch, 12.75 ppf, 13Cr HCS production tubing. The well was tested in order to characterize the reservoir, determine the completion efficiency and ascertain reservoir limit for GIIP estimation. The test program involved multirate production, followed by a build-up phase for which a Down-Hole-Shut-In-Tool (DHSIT) was deployed to manage wellbore storage effects. However with the conclusion of the multirate test, and commencement of build up, the downhole shut in tool (DHSIT) failed and subsequently the well was shut-in at the surface and the build up (BU) stage allowed to progress as per programme.
Following the conclusion of UGO-1X multi-rate test (MRT drawdown and build up), the data was retrieved from the quartz gauges, quality checked and analysed using the conventional and numerical simulation methods.
This paper illustrates the difficulty of interpreting an incomplete set of data, the importance of properly understanding the operational history in well test analysis as well as the usefulness of conducting a quick analysis to validate data thereby avoiding a repeat operation. It is shown that by careful reprocessing of the data (de-listing data within the DHSIT failure interval), the overall quality of the data could be significantly improved and used to produce credible results. This made it unnecessary to conduct a repeat of the MRT/BU on UGO-1X as initial test objectives were achieved.