bluuebunny/crossref_metadata_2025 huggingface dataset:
CO2 EOR and Sequestration in a Depleted Gas-condensate Reservoir: UKNS Case Study
Authors: Mogbo Obuekwe
Published: July 2011

This paper comprises a portion of a development study to investigate the applicability of CO2 for enhanced oil recovery and sequestration in a field in the central UKNS. The study focused on compositional simulations to predict the Minimum Miscibility Pressures, describe prognosed miscibility mechanisms and estimate incremental hydrocarbon recovery from full field simulations.

Depleted gas condensate fields are important targets for CO2 sequestration/EOR. Once depleted below the dew point, retrograde condensate is deposited in the pore system. CO2 injection in the depleted gas condensate reservoirs may allow enhanced gas recovery by liquid re-vaporization and reservoir re-pressurization or pressure maintenance.1 It is also noted that an accurate EOS fluid characterization is essential for CO2 miscible displacement, which is a composition-sensitive process. 2 As such, compositional modelling is preferred.

For the phenomenological stage of the study, 1D slimtube compositional simulation models were used to estimate the Minimum miscibility pressure (MMP) of representative fluids in the Oil and depleted gas condensate legs. Different grid-block sizes were used to consider the effect of numerical dispersion on the MMP. Subsequently, ID finescale block compositional simulation models were used to study and verify the multi-contact miscibility mechanism existent in the depleted condensate legs.

The 3D full field model is highly compartmentalized with nine different panels having separate PVT characteristics. Each panel has a 12 component Peng-Robinson equation of state which is conditioned to its individual fluid. CO2 injection for repressurisation is simulated up to and beyond MMP, contact miscibility is attained and gas cycling is implemented for incremental oil recovery. After EOR, production ends and injection is continued for estimation of the maximum amount of CO2 to be sequestered. Furthermore, typical economic analysis for CO2 EOR project justification is done. The results enabled correct investment decision making by showing that CO2 EOR is technically but not economically justified for this field.
Developing Petroleum Engineering Young Technical Professionals in Shell Nigeria – The Well Site Petroleum Engineer Model
Authors: Ebitu Sophia
Published: July 2011

The introduction of the "Drilling in the 90s" concept resulted in the loss of the Well Site Petroleum Engineer (WSPE) position on rigs, which hitherto was the generally accepted development format for graduate recruits in the Petroleum Engineering function in major IOCs through the ‘70s and ‘80s. A two-year stint as a WSPE on drilling and workover rigs was usually followed by development opportunities in one of the PE disciplines with an opportunity to grow into a PE technical professional. A review of job competence profiles performed around the middle of last decade among young to mid level Petroleum Engineering professionals showed deficiencies in skill levels due to limited exposures to field operations at the Young Technical Professional (YTP) level following the discontinuation of the programme; new joiners into the PE disciplines remained office based in respective asset or discipline teams, going into the field for visits to learn or witness specific drilling and field operations which usually focused around discipline interests and generally lacked structure, depth and the required levels of exposure to field operations. In order to address this problem, the WSPE programme was reinstated to bridge skill gaps by field exposure, thereby producing more competent YTPs prepared for growth up the PE career ladder. This paper presents a review of the competency gaps observed with the suspension of the WSPE programme and describes the WSPE & Field Exposure model adopted by Shell Nigeria, which is considered a key element in developing competent PE's through a structured exposure to the practical aspects of oilfield operations in the first two years of their career.
Dynamic Analysis of Stick-Slip Motion of Drillstring While Drilling
Authors: Omojuwa E. , Osisanya S. , Ahmed R.
Published: July 2011

Drilling dynamic dysfunction condition occurs when dynamic forces in the drillstring cause very high stresses and fatigue or physical damage to the string and thus reduced bit performance or caused wellbore damage. These forces may generate from vibrations, shocks, oscillations, and BHA dynamic buckling. Failure of drillstring components due to torsional stresses are caused by torsional vibrations. This work investigates the response of drillstring to torsional vibrations through analysis on an elemental stepped-shaft drillstring model in a vibration damping medium. The work directs its analysis on the stick-slip motion, which is the most common form of torsional vibrations of drillstring while drilling.

The interaction between the wellbore and the drill-bit is identified in this research as the source of excitation, that is, as the downhole vibratory source. Hence, the exciting torque is derived from the resolution of forces and reactions at wellbore-drill-bit contact. The response equations obtained from theories of mechanical vibrations and mathematical principles in this research are in two forms: the transient state and steady-state responses. This work is different from other similar works where only the steady-state response is presented. A computer program was developed and tested with suitable drilling data to solve the response equations. Extensive vibration analysis was carried out using the program to examine the responses of different forms of excitations. Beside this, the effectiveness of a torsional vibration absorber was discussed with regards to reduction of drillstring oscillations. The torque-rectification control (TRC) system was introduced and analyzed as regards its use for automatic vibration control during drilling. Simulation results from the computer program show the impacts of torsional vibration absorber and TRC system. In conclusion, recommendations are given based on practical solutions to the problems of drillstring vibrations and from the findings of this project.
Economic Analysis of GTP, GTL, CNG, NGH for Offshore Gas Development in Nigeria
Authors: Osokogwu U. , Ademujimi M. , Ajienka J. A
Published: July 2011

Natural gas consumption is globally increasing as it is one of the most important energy resources today. Its consumption is accelerated because of the growing environmental concern. To respond to this world demand, the alternatives of gas usages and technologies should be investigated and compared in terms of economic feasibility. The economic viability of Gas-to-Liquid (GTL), Gas-to-Power (GTP), Compressed Natural Gas (CNG) and Natural Gas Hydrates (NGH) depend on the following factors namely; Capital expenditures (Capex), Operating expenditures (Opex), Prices (natural gas price), Net present value (NPV), profitability index, internal rate of return and Payback time. From the above mentioned factors, at 15% discount rate, CNG has NPV of $16.2 billion, IRR of 54%, profitability index of 7.2 and payback time of 1year and 3 months. GTP has a negative NPV (indicating loss), IRR of 54%, profitability index of 0.8 and payback period 3 years and six months. GTL has NPV of $6.5 billion, IRR of 50%, profitability index of 2.2 and payback period of lyear and 3 months. NGH has NPV of $7.0 billion, IRR of 42%, profitability index of 1.1, payback period of 2 years and 4 months. These results show that Compressed Natural gas is preferred to others because CNG has the highest net present value (NPV), highest profit to investment ratio, highest internal rate of return, lowest initial expenditure (CAPEX) and a shorter payback period. From the economic aspect of this work compressed natural gas is the most economical and viable.
Economics of Monetisation of Stranded Gases in Nigeria
Authors: Joseph A. , Umeogu O. , Ajienka J. A. , Ikeh L
Published: July 2011

Nigeria is endowed with abundant natural gas reserves. Over the years, pipelines and LNG have been the two major means of gas transportation and hence, the main utilisation media in the world. However, in some areas in Nigeria, reserves are found in difficult locations and in quantities that make their exploitation through these conventional ways techno-economically unfeasible. The goal of this study is to investigate with the aid of several economic indicators, risk analysis and sensitivity analysis; the different ways in which natural gas can be employed economically as an energy resource for both power generation and road transport. The analysis covers both the natural gas use as a Power generator, fuel - Compressed (CNG) or Liquefied (LNG) - and as a feedstock to produce other fuels - synthetic (GTL) Naphtha and Diesel (F-T diesel), and Liquefied Petroleum Gas (LPG). After a thorough scrutiny of the various options, the GTL-incorporated Power Generation with 70% steam supply was found to be the most economical and environmentally friendly option for the energy generation. If properly harnessed, it could generate huge potential revenue for the government, resolve the epileptic power supply problem and create employment opportunities.
Effect of Water-Cut on Sandstone Strength and Its Implications in Sand Production Prediction
Authors: Joseph A. , Ilozue C. T , Osokogwu U , Ajienka J. A.
Published: July 2011

Production of water is inevitable from reservoirs particularly in aged fields. Water is very useful for efficient reservoir management but could be a nuisance when it does not contribute to hydrocarbon production and cause diverse problems such as corrosion, sand production, etc, in a well. High water cut increases the potential of sand production risks. Several mechanisms of sanding, sand control models and measures exist in the industry to ensure safe operation of facilities. In this work, series of laboratory triaxial compressible strength tests on different core samples was performed to investigate and quantify the effect of water-cut on sandstone strength and sand production. The tri-axial compressive strength tests were performed under in-situ confining pressures. The samples were initially 100% saturated with brine at some time and other times the water-oil saturations were varied. The results showed that the effect of water-cut on sandstone strength and sand production is very significant for all sandstones tested. Also, strength reduction is more significant for 100% water saturated samples than samples with less water saturation for all samples. Hence, water saturation-induced rock strength reduction is the most significant factor governing sand production. Although, failure of rock is pre-requisite for sand production, the failure does not always lead to sand production
Effectiveness of Safe Welding Systems in Eliminating Shut-in on Offshore Oil and Gas Platforms
Authors: Hutchinson Todd , Oyeyinka Dotun
Published: July 2011

Installations used in oil and gas industry are usually large metal structures. These structures are affected by environmental factors, and are in need of constant maintenance and repair.

HAZTEC, which stands for Hazardous Atmospheric Zone Telemetry for Environmental Control, is an automated Monitoring and Control System that utilizes a custom automated program and a Safe Welding Enclosure. Together these elements create an isolated safe zone around the work area, allowing hot work to take place in hazardous-rated locations by monitoring and controlling all hot works.

Each HAZTEC Safe Welding Enclosure is custom-designed and built to fit each particular situation without disrupting or altering the area or existing equipment. The HAZTEC enclosure is built using fire-retardant wood, and each element of the HAZTEC enclosure is constructed according to OSHA and MMS standards. The flooring of the HAZTEC enclosure is further lined with a fire-resistant blanket, rated at a maximum of 3,500 degrees Fahrenheit, and a layer of light-gauge stainless steel that dissipates heat by dispersing slag and sparks. This process and material may also be used on walls or other areas of the enclosure where heavy overspray from welding or metal washing may occur.

Before any hot work begins, all openings of the HAZTEC enclosure are sealed, filtered, or closed to create a positive pressure over balance in the interior of the enclosure, protecting the inside atmosphere from exposure to the potential dangers of the outside atmosphere. A minimum positive pressure differentia water column is maintained and monitored inside the enclosure throughout the hot work procedure. A filtered-air discharge outlet allows smoke to vent while maintaining no less than the minimum requirement of the positive pressure over balance.

The overall benefits of using the HAZTEC enclosure include retained production, optimized scheduling, safety and shared tasks.
Efficient Reservoir and Production Management "LCEEM and CEEM Approach"
Authors: Biu Victor. T. , Buduka Stanley , Prince Wachuku
Published: July 2011

Once new fields are discovered, ensuring maximum recovery of probable reserve before abandonment is the focal point of sound reservoir and production management practice.

Efficient reservoir and production management practice involves the use of advanced technology such as commercial, local and in-house software, highly skilled human resources, real time analysis, adequate and consistent multi-disciplinary reservoir to well monitoring approach on subsurface and surface facility bottlenecks for optimal field development. Nevertheless limited availability of advanced technology does not potent failure for successful optimization of any reserve, especially in marginal field development; however full integration of available human resources and consistent monitoring remained the critical driving factor for reserve optimization. This paper presents a comprehensive analysis of CEEM and LCEEM which involve interdisciplinary and consistent daily well-reservoir and field monitoring practice with design PRMP that will help to maximize well-reservoir-field potential. The entire process whether LCEEM and CEEM is recycle, hence a monitoring check valve and flexible well – reservoir management plan is necessary.

The LCEEM and CEEM shows that creating a performance check box and several scenario chart remains a key monitoring tool for well-reservoir-field production optimization and reserve maximization.
Energy Resources in Africa: Curse or Blessing?
Authors: Odizuru-Abangwu I. N
Published: July 2011

The African continent is blessed with abundant natural resources and specifically, significant energy resources but Africa has the greatest energy challenge in the world. Why is that and what can be done about it? Is Africa under a "resource curse"? This article explores the concept of "resource curse" and its implication for the continent of Africa.

Africa currently has 127.7 thousand million barrels of proved oil reserves, representing 10% of the total world oil reserves. The continent is the 3rd largest oil producer in the world, representing 12% of world oil production in 2009 but only utilizing 3.7% of it. This typifies the current situation in the continent whereby they are large resource holders and producers, but very poor resource users. The direct relationship between energy utilization and economic development is further explained in this article, buttressing the strategic nature of the energy sector in the development of Africa.

Other unique opportunities are explored in this article including renewable energy resources such as solar and biomass which can potentially turn around the energy dynamics in Africa. It also explores the unique challenges facing energy utilization in Africa including poor infrastructure, environmental concerns as well as political and leadership challenges.
Evaluation of Horizontal Well Completion and Performance Efficiency Using a Visual Basic Software – H-WELLEFF
Authors: Olu-Akinyemi E. G. , Ajienka J. A.
Published: July 2011

Horizontal wells have been drilled for over two decades, because of their ability to exploit tight reservoirs, thin reservoirs, discontinuous reservoirs, naturally fractured reservoirs and the need to minimize water and gas coning/cusping. In general, horizontal wells lead to increased productivity due to a greater surface area contact with the reservoir. This research work used a visual basic software H-WELLEFF to calculate the various indicators used in the industry for evaluating horizontal well completion and performance efficiency. These indicators are Analytical PI's, actual PI from welltest data, WIQI and FE. The software breaks the skin down into mechanical skin and pseudo-completion skin and calculates the percentage damage (reduction in efficiency) due to each of these skin factors. Also Case studies were carried out to see how the various indicators respond to change in factors that contribute to the total skin.

H-WELLEFF presents a good tool for calculating horizontal well efficiency and also for observing the trend of productivity index and damage over time.
Facies-Based Saturation Modeling—Bonga Field
Authors: Kalu E. C. , Arogun O. O. , Pirmez C. P.
Published: July 2011

The initial Bonga field development was based on a "green field" integrated saturation model using Gulf of Mexico (GoM) data as analogue. In an earlier revision of the Field Development Plan, the relative permeability and capillary pressure models were based on steady-state and centrifuge special core analysis (SCAL) experiments from a few Bonga Main wells and also integrating GoM data. The saturation modeling was dependent on permeability classes (intended to be, but not explicitly representative of the facies). As production continued over the years, several attempts have been made at history-matching the observed performance history of the reservoirs that constitute the Bonga field. The results indicate that a review of some of the input parameters including the relative permeability and capillary pressure model are required to obtain a reasonable history match of the reservoir performance.

The predominant facies types in Bonga field include Channel Storey Axis (CSA), Channel Storey Margin (CSM) and Inter-channel Thin Beds (ICTB). A relationship was observed between the raw SCAL data and the different facies classes from detailed core description. Current production and recent drilling/logging information coupled with 4D seismic monitor indicate preferential sweep from some of the facies. This may have a significant impact on the ability to maximize recovery from the various facies in the reservoirs.

This study focuses on developing a facies-dependent saturation model that honors the current understanding of the waterflood performance of Bonga reservoirs. Good history-matched, robust and fit-for-purpose models were obtained using this methodology. This has led to better evaluation of the recovery efficiency and flood pattern of the field which has been used to support further field development options and optimize production from existing wells.
Field Case Deepwater Development Wells Clean-up and Testing
Authors: Onyeanuna Chinedu , Marpaung Fivman
Published: July 2011

This paper presents the experiences of well clean-up operations carried out in the development wells of Akpo deepwater field.

Akpo is located 135 km offshore Nigeria in 1400 m of water depth. The reservoirs consist of faulted, unconsolidated, turbiditic channel and lobe sands with complex architecture. The fluids in each reservoir are near-critical. The field is currently producing about 175,000 barrels of condensates per day.

Current sand control techniques are Frac-Pack (FP), Stand Alone Screen (SAS) and Expandable Screen (ES).

Early data acquisition during well clean-ups was essential in other to optimise the development strategy, ensure a production ramp-up in line with expectation and reduce remaining uncertainties which were mainly linked to sand communication within channel complexes, fluid behaviour, and faults behaviour (seal or conduit).

The paper covers the clean-up design, execution, operations monitoring, data acquisition, and fluid sampling, along with the challenges and constraints encountered in the process for the different wells.

It describes how the challenge of hydrates formation, exacerbated by the deepwater environment and peculiar nature of the reservoir fluid, was handled to ensure successful well clean-ups. It also gives an example on how the early data acquisition program impacted important field development decisions.
Field Development and Optimization Strategy of a Giant Gas Reservoir in the Gbaran-Ubie Node
Authors: Cordelia Ikpera , Esta Eleluwor
Published: July 2011

The XON field is one of the five fields in the Gbaran-Ubie node to supply gas to Nigeria Liquified Natural Gas and is a field case history to illustrate the techniques and benefits of field development optimization right from initial field optimization to well delivery.

The XON AB4000X reservoir is one of the largest Non Associated Gas reservoir in SPDC and is expected to provide more than half the gas required for Gbaran Central Processing Facility capacity of 1Bscf.

Gas reserves from the 2003 Field review went down from 1.6 Tcf to 1.25 Tcf post the drilling of XON 7 and forecast based on new volumes indicate that the planned total reservoir offtake of 500 MMScf/d (100 MMScf/d per 5 gas producer planned for the reservoir) will only be sustained for 3 years instead of 5+ years. Following this, it became necessary to accurately estimate the Gas Initially In Place(GIIP), Ultimate Recovery (UR) and also provide an optimum development plan for this reservoir based on the new available data.

An optimisation optimization team was put in place to build new static and dynamic models based on new available data to be used for:

Accurately estimate in place volumes and UR Optimise expected reserves the Reservoir Development Plan Support drilling campaign

The optimization optimization results have led to increase in expectation GIIP to 2.03 Tcf, represent a 22% increase over the 2003 Field Review and a 63% over the 2005 estimate. The CIIP increased to 106.0 MMstb, representing a 23% over the 2003 FR estimate. Total gas recovery has also increase to 1.26 Tcf which is about 20% from 2003 Field Review (FR). Production rates increased from 100 to 150 MMScf and compression scope of about 500 Bscf to further add value to the filed development.

Most of the wells were delivered as top quartile wells due to collaboration between the asset, project and well engineering teams.
Foam Cementing Design and Application: A Cure for Low Gradient-Associated Problems in Deepwater Operations in the Gulf of Guinea
Authors: Taiwo Oyetade , Ogbonna Joel
Published: July 2011

Cementing in the deepwater environment could pose some challenges because deepwater formations are buried with much reduced overburden. This gives a lower fracture gradient resistance than the same formation at the same sedimentary depth onshore. In situations like this, the relative density-to-compressive strength ratio of the cement slurry used for zonal isolation becomes critical; hence foamed cement helps to address these challenges. Slurries ranging in density from 4 to 15 lb/gal can be prepared with foamed cement. Foamed cement can be used at temperatures from 28 to 600ºF (82 to 1112ºC). In this project, Laboratory analysis of foamed and unfoamed cement at different slurry weights was determined and compressive strength results were evaluated. Test results indicated that the compressive strength for 12.0 ppg unfoamed cement after 24 hours was 254psi while the foamed slurry of 11.8 ppg gave compressive strength of 1050 psi after 24hours. It is imperative to note that conventional slurries at higher slurry weight that will give higher compressive strengths will fracture weak formations and not recommended. Foamed cement slurry offers a comparative advantage of enhanced mud removal, good ductility, fluid loss and gas migration control, insulation properties and excellent compressive strength development at low slurry density. However, the disadvantage of foamed cement is the need for specialized cementing equipment for both field application and laboratory testing, nevertheless, the associated benefits arising from application of foam cement in deep water weak formation environments makes it a slurry of choice in locations such as Gulf of Guinea.
Formation Pressure While Drilling (FPWD) Tool Application in Reservoir Management–Case Study on Tetra-Mega Field, NYC Nigeria
Authors: Duru Elizabeth C. , Liu Forrest , De Santo Ilaria , Odewoye Oluwatosin
Published: July 2011

The Tetra-Mega field development project, operated by NYC Company, has expanded since its onset a number of years ago. The daily plateau production of this field is expected to be high based on its huge proven reserves. To maximize the value of this hydrocarbon asset, employing the well construction process of drilling wells that can achieve maximum production potential is highly recommended. The use of technologies that enable optimal and precise wellbore positioning, increased well lengths, and enhanced understanding of reservoir characteristics is crucial to the successful development of the field. For this reason the Formation Pressure While Drilling (FPWD) tool has been consistently deployed in the Tetra-Mega field. The tool's capability of acquiring good quality formation pressures and fluid mobilities in a timely manner, while drilling complex well architectures in tough drilling environments, has established its position as a valuable tool for reservoir management applications.

A peculiar approach introduced here focuses on performing well-to-well reservoir evaluation studies, prior to the commencement of field development studies. Based on this approach, the value of the information provided by the FPWD tool to Tetra-Mega field development is the main focus of this paper. Since its introduction to the field a few years ago, the tool has been efficiently used to acquire good quality formation evaluation (FE) data in real-time. Well-to-well evaluation studies in this field involved the use of FE data to do a pressure profile of the field so as to identify its different reservoirs. Further analysis into individual sands investigated pressure continuity, reservoir compartmentalization, potential thief zones and fluid identification. This enabled a better understanding of the reservoir behavior, and thus optimized well placement and completion strategies. NYC was able to make immediate plans and take actions to address specific problems and opportunities in the reservoir development of this field. Additionally, acquiring formation evaluation data during the drilling phase of the well is valuable to NYC in saving substantial rig time and cost.
From Design to Operate Phase: Sand Control and High Rate Turbidite Well Performance
Authors: Okoh Ehimhen , Oluseye Ogunsina , Green Allen
Published: July 2011

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<5), with average grain size ranging between 198 - 260µm, low clay content (< 4 wt %), and limited amount of fines (< 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

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

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

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

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

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

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

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

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

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.