bluuebunny/crossref_metadata_2025 huggingface dataset:
A Systematic Approach to E-Inflow Control for Horizontal Well Production Optimization in Shale Oil Reservoir
Authors: Makinde Favour A.
Published: July 2016

Shale oil reservoirs are characterized by low porosity and very low to extremely lowpermeability which makes the oil content difficult to produce at economic rates without being enhanced. The current production optimization technique in the oil industry uses a combination of horizontal well and fracking. However, there is a possibility of linearly increasing inflow with high liquid loading at the horizontal well heel which can seriously choke offtake of the fluid.

This paper, therefore presents a holistic approach based on wellbore hydraulic optimization and systematic inflow control to maximize deliverability from shale oil reservoirs. Wellbore hydraulic optimization was achieved through rheological characterization of viscous liquid-rich shale at different nodes whilst systematic inflow control was achieved through selective inflow control into the wellbore in order to distribute fluid influx uniformly and avoid early breakthrough of unwanted fluids.

The results presented prove that using the new modelling approach offers better deliverability overall compared to the current approach known.

Hitherto, there has not been a holistic characterization of fluid rheology cum systematic inflow control, this work offers this novel approach as a contribution to the existing methods of optimizing production from shale reservoirs.
A Proxy Based Approach for the Preliminary Evaluation of New Gas Condensate Field for Development
Authors: Omeke James E. , Ezeukwu Toni , Adesun Julius , Ekesiobi Chidi
Published: July 2016

With increase in gas demand to meet both export and domestic gas obligations, amidst oil price volatility, it is imperative that oil and gas companies embarks on activities that will minimize investment risk and initiate robust development plans. It becomes a very big challenge at the onset of new gas condensate field development owing to limited geological and engineering data.

To ascertain the technical feasibility and economic attractiveness of a gas condensate field, a very lengthy study work is required to unravel the complex interplay of subsurface uncertainties; hence, a quick screening tool is therefore required for quick decision making and investment prioritization. A proxy of recoverable reserve for the new field was developed for this purpose using design of experiment (DOE) and response surface model (RSM). However, although DOE was initiated in the industry to reduce computation, it remains computationally expensive especially in compositional simulation were many degrees of freedom exist in the uncertainty parameters.

This study presents a new gas condensate field case study where both engineering and earth model variables were systematically varied to assess the impact of main uncertainties on forecast level of gas condensate production/reserves using RSM proxy. This approach was validated when key risks associated with new gas condensate field development were quantified.

This paper provides a technical and economic feasibility assessment tool for low risk decision. It will also assist in data acquisition program and roadmap construction especially when the most influential uncertainty parameters influencing gas and condensate recoveries are identified.
Borehole Stability Management Using the New Mudweight Window Concept; A Case Study of Well KTY 02, KTY 03 and KTY 04
Authors: Bassey Akong , Dosunmu Adewale , Otutu Friday , Usim Mike , Majekodunmi Kamaldeen
Published: July 2016

Borehole instability is one of the major factors that contribute significantly to additional unplanned cost in drilling operations irrespective of the wellbore inclination. Problems generally build up in time, starting with the tensile or compressive failure of the borehole wall, followed by transfer of fragments to the annulus and finally-if hole cleaning is insufficient-culminating in such difficulties as tight hole, breakouts, caving, pack off, borehole collapse and stuck pipe.

Horizontal and highly deviated wells in normal faults stress regimes present more difficult challenges than low inclined wells due to compressive or shear failure of the wellbore. Wellbore stability issues are more pronounced as the wellbore stress difference reaches at maximum with increase in inclination. Proper planning of the well trajectory and mud weights are crucial to avoid such complexity which causes huge rig downtime, NPT and cost. With the aid of in-situ stress, pore pressure and rock strength analysis the wellbore stability can be assured with suggested optimum deviation profile and mud weights window for different inclinations and azimuths.

An attempt has been made to perform the wellbore stability analysis for three high angle and three horizontal wells (with drain-extension of about 500ftahd) development wells in Niger Delta which is planned for production in near future. In our workflow, the seismic data and offset well information have been incorporated to generate pore pressure, optimum mudweight, shear failure (minimum envelope) and fracture pressure gradient. Rock physical parameters have been calculated from the offset well's logs and calibrated with laboratory tested dataset to use in the stability analysis for well KTY 02, KTY 03 and KTY 04. In the study area, wellbore stability analysis was carried out in both the pilot and drain hole sections of the horizontal wells. However, because of horizontal drilling plan in drain holes, differences in principal stresses in the wellbore and their physical implication on stability was plotted and interpreted through stress concentration plot and safe MW window analyzer extensively. The stresses and the rock strength datasets input were used to derive the collapse failure gradient curve (CFG) using the Mogi failure criteria. The wellbore circumferential and radial stress distribution analysis has been done for different depths with the inputs from stresses and the corresponding cohesive strengths and the Frictional Angles.

With these analytical results, we have recommended the wellbore trajectory along Shmin and SHmax direction and along the maximum good reservoir facies with corresponding mud weight (window) profile required to drill these wells with NPT as a result of instability consequences such as stuck pipes and jeopardizing wellbore integrity during logging, casing running and completions.
Capturing Reservoir Communication Uncertainty in a Well Proposal Assessment
Authors: Idogun Iroro , Lawal Olumide , Eme Vincent , Oguntona Bayo
Published: July 2016

As Oil fields containing stacked reservoirs are developed, it is not uncommon for these reservoirs to be in pressure communication. The extent of pressure depletion may determine the viability of potential new drills. Possible communication of the X1 reservoir with the Y1 reservoir was initially suspected when a Material Balance study earlier conducted on the X1 reservoir did not yield a reliable historical pressure match using mapped volumes of the X1 thereby suggesting potentially larger Oil in Place number in the X1 reservoir. Also, the structural overlay of the X1 over the Y1 reservoir having compatible hydrocarbon contacts seemed to also indicate possible communication between the X1 and Y1 reservoirs. The conclusion of the Material Balance study recommended a more detailed probe into the X1 reservoir to ascertain the impact of communication on the reservoir development strategy.

A simulation study was conducted primarily to evaluate the impact of communication uncertainty on the new drill recovery. Three scenarios were considered namely: Communication of the Y1 with the X1 through the aquifer; Communication of the Y1 with the X1 through the hydrocarbon and the Y1 completely isolated from the X1. The history match indicates reservoir communication through the aquifer as the most plausible scenario. However, due to active reservoir drive mechanism of gas Cap expansion and strong aquifer support in the X1 reservoir and possibly same in the Y1, all three scenarios did not adversely affect the potential recovery in this instance with recoveries between 50-59%. Hence incorporating surveillance information from offset producers is vital in evaluating production potential of zones which may be unproduced but not virgin.
Cubic Spline and Graphical Techniques for Determining Unsteady State Relative Permeabilities in Field Cores
Authors: Mamudu Abbas , Taiwo Oluwaseun Ayodele , Olafuyi Olalekan
Published: July 2016

Relative permeability is one of the key factors in reservoir engineering calculations to simulate multiphase behavior in porous media. The relative permeabilities calculated from established models do not perfectly characterize the reservoir without a known trend or history. This necessitates the need to use a reliable and globally accepted technique based on Niger Delta field production data for calculating relative permeabilities from the fields so that the models derived from the relative permeability curves could be tamed and domesticated in the region for better reservoir characterization and evaluation. The Johnson, Bossler and Neumann (JBN) method is the industry standard for measuring relative permeabilities from field cores. In order to eliminate the need of using numerical differentiation, and therefore reduce the overall numerical error in this method, a graphical technique was proposed and implemented during late 70s. However, with splines, the numerical differentiations are still done but with improved results.

The current study presents the results from the comparative analysis of two approaches employed to avoid the traditional numerical differentiation required by the JBN method. Production data from field cores in the Niger Delta were used. The graphical method and cubic spline numerical modeling were both used to calculate the individual relative permeabilities from the pressure/production history of the displacements. the results were analyzed and compared. The results of both methods show a very good match over a fairly small saturation range and also differ. However, cubic spline results are closer to the traditional numerical differentiation results because is a modeling approach in which the numerical differentiation is incorporated with improved accuracy.
Managing Fluid Properties Uncertainty in the Evaluation of a Greenfield Gas Development: The Dex Field Case
Authors: Sonde Adenike , Azubike Obi , Ozoemene Uche , Fasasi Roseline
Published: July 2016

In planning the development of a gas field, the gas properties play a critical role in estimating the economic value of the gas development. Chief amongst these gas properties are the Condensate-Gas Ratio (CGR) and the gas formation volume factor (Bg). While the gas volumes to be developed at standard conditions are dependent on the gas formation volume factor (or the expansion factor), the CGR determines the volume of associated condensate that can be produced and sold. A good understanding of these properties is therefore required for the evaluation of any gas field development.

Fluid properties, ideally, are determined from laboratory PVT experiments carried out on fluid samples acquired from the field. These experimental PVT data are vital, especially in green fields where there is no production data that can be used to estimate some of these properties. Where such good quality experimental data are not available, it poses a major uncertainty around the fluid properties, particularly in a green field.

The Dex field, a green field which is predominantly gas-bearing, has been penetrated by six wells, and fluid (PVT) samples were acquired from the last appraisal well drilled in the field. However, besides compositional analyses, extensive laboratory analyses could not be carried out on these samples due to the high level of mud contamination. While the compositional data provided some qualitative data and information on the fluid, the fluid properties essentially remained uncertain. This paper describes how this uncertainty was managed and how a reliable range of fluid properties was generated for use in the Dex gas development evaluation.
Experimental Investigation of the Feasibility of Polymer Flooding in a Shallow Niger Delta Oil Reservoir
Authors: Ogienagbon Adijat , Taiwo Oluwaseun Ayodele , Mamudu Abbas , Olafuyi Olalekan
Published: July 2016

The global oil price as well as Nigeria’s current reserve is on a continuous alarming decline. With the increasing finding cost of new wells and demand for energy, improving oil recovery from existing wells becomes highly pertinent. Generally, waterflooding leaves approximately two thirds of the OIIP as un-swept or residual oil resulting to a low recovery factor. The improvement of recovery factor is one of the identified five Research & Development (R&D) grand challenges or upstream business needs highlighted by the SPE R & D committee. Enhanced Oil recovery (EOR) methods provide an avenue to Petroleum engineers to unravel this challenge. In lieu of this, we investigated the feasibility of improving recovery with polymer flooding technique in the Niger Delta region of the Sub-Sahara Africa. A sequence of brine saturation, oil saturation, water flooding and polymer flooding was carried out on four different cores (core A, B, T & R). Core A & B are ROBU cores (specially manufactured synthetic cores), T is Bentheimer core and while R is a reservoir rock core sample from a shallow central Onshore Niger Delta reservoir.

The results show comparative responsiveness of oil recovery to polymer flooding by the various core samples. Core samples T & R are good candidates for polymer flooding having produced 21.28% & 13.33% after polymer flooding. Model Bentheimer rock sample (T) which has close petro-physical properties to that of the case studied reservoir has the highest displacement efficiency of 52.63%. The core flood analysis demonstrated that polymer flooding could improve oil recovery within the Central Onshore reservoir of the Niger Delta.
Impact of Data Quality on Well Operations: Case Study of Workover Operations
Authors: Enyekwe Alfred , Urubusi Osahon , Yekini Raufu , Azoom Iorkam
Published: July 2016

Significant emphasis on data quality is placed on real-time drilling data for the optimisation of drilling operations and on logging data for quality lithological and petro-physical description of a field. This is evidenced by huge sums spent on real time MWD/LWD tools, broadband services, wireline logging tools, etc.

However, a lot more needs to be done to harness quality data for future work-over and or abandonment operations where data being relied on is data that must have been entered decades ago and costs and time spent are critically linked to already known and certified information.

In some cases, data relied on has been migrated across different data management platforms, during which relevant data might have been lost, mis-interpreted or mis-placed. Another common cause of wrong data is improperly documented well intervention operations which have been done in such a short time, that there is no pressure to document the operation properly. This leads to confusion over simple issues such as what depth a plug was set, or what junk was left in hole.

The relative lack of emphasis on this type of data quality has led to high costs of work-over and abandonment operations. In some cases, process safety incidents have arisen.

This paper looks at some work-over operations carried out in a span of 10 years. Data management system is generally analysed and a categorisation of issues experienced during the work-over operations is outlined. Time lost due to data error was seen to average 1.54% but with a unit peak of 19%. An analysis is done on the wells' activity history to check for correlations. Bottlenecks in data management are defined and solutions currently being implemented to manage these problems are listed as recommended good practices.
Project Finance for Indigenous Oil and Gas Companies in Nigeria: An incentive for Energy security and Stability
Authors: Essien Oluwadamilola Ayomide
Published: July 2016

The energy industry is highly capital intensive, hence the reason for a very few but powerful players in the industry. The disadvantage of this to a developing country like Nigeria is that new, ambitious upcoming indigenous companies, may not be able to make significant achievements in this industry because of the amount of capital required to operate in this industry.

One method of financing capital intensive projects is through project finance. In the financing of a project, the lenders would be satisfied to look to the project being financed as the source of repayment for the loan. The project sponsors are only liable to the lenders in the event of a breach in the equity contributed to the project and no more. As good as project financing may sound in the ears of a project sponsor particularly, it comes with loads of obligations and responsibilities. Every participant in the project is made to be economically interested in order to ensure that all parties are working towards the success of a common goal. The obligations are taken higher and thus lenders confidence boosted when they are able to secure a sovereign guarantee from the host government. However, these guarantees may be given depending on the importance of such projects to the economic development of the country, the debt ceiling of the government and also the current financial state of the government. (Duke 2016) Because of the uncertainties that may surround soverign guarantees, project lenders are more satisfied to obtain guarantees and political insurance from multilateral organizations as well as private insurance companies on a given project. (Duke 2016) At the heart of project finance is risk identification and allocation. Given that it is impossible to identify and allocate all anticipated risks, where a large chunk of the risks can be identified and allocated, the lenders would be satisfied to finance oil and gas projects in Nigeria which in turn promotes energy security and sustainability in Nigeria.
Zoning Steam-Heated Reservoirs by Heat-Transfer Mechanisms
Authors: Lawal Kazeem A.
Published: July 2016

In-situ oil recovery by thermal methods entails introducing heat into the reservoir to enhance productivity and ultimate recovery. Clearly, proper design and management of thermal floods require adequate insights into the temperature distribution in the reservoir. This paper interrogates the robustness of the traditional approach of describing steam-flooded reservoirs with two isothermal zones. Employing a rigorous one-dimensional reservoir-heating model, the spatial distribution of the heat-transfer mechanisms during each of conduction, convection (non-condensing) and multiple-contact condensation processes has been investigated. After a sufficient period of heating, the prevailing temperature profiles are analysed and the reservoir delineated into zones according to the temperature responses. From the simulation results, the thermal front is mapped, and the dominant heat-transport mechanisms at its leading and trailing edges are analysed, both in space and time. It is found that a maximum of four zones vis-à-vis condensation, convection, conduction and quiescent, can be identified at any instant of a thermal flood. However, the presence and relative thickness of the zones are controlled by the maturity of the thermal flood and the dominant process (conduction or convection) at the time of interest. In practice, these findings should find applications in the design and management of thermal floods, on both laboratory and field scales.
Seismic Constrained 3D Static Modelling: Conceptual Model Replication by Integrating Analogues and Seismic Facies
Authors: Kehinde Oyeleke Zaid , Olatunbosun Afolayan
Published: July 2016

Subsurface risks involved in a field development activity are best mitigated by establishing a narrow uncertainty band from all available subsurface data. Horizontal wells, based on their profile usually presents a set of ‘point’ data for a number of spatial location along the bore, however these information are usually not accurately captured in the development of a conceptual model.

This field study attempts to show the integration of data from horizontal wells, analogue and seismic in order to accurately predict facies/reservoir properties distribution and also look into the production potential of a newly drilled offshore production and injector wells.

The study area is situated in the deepwater South west of Niger Delta, Nigeria. An integrated approach which incorporates statistical and neural network seismic attribute analysis, horizontal well point properties, and analogue data to generate a robust depositional facies distribution was adopted in the static modelling. The facies model being an underlining step in distribution of reservoir petrophysical properties was then utilized to generate descriptive reservoir properties model that captures the subsurface heterogeneity of the "Zat" field. The correctness of this methodology is being substantiated by result culminated from other similar projects.

The depo-facies accurately captures the stratigraphic geometry and distribution of facies as seen by wells and seismic thereby leading to improved lateral and vertical facies predictions. So what you see is what you get! The interplay of along well-bore and three-dimensional prediction of sand intervals enables a better QC workflow for assigning petrophysical properties (e.g. porosity, permeability and water saturation) to the static model. The trend and connectivity of amalgamated channel bodies mimic to a greater extent the observed seismic and wellbore facies.

The resultant net-to-gross estimation of this approach compares better to the seismic data set prediction from inversion.
PVT Analysis: Validity Checks and EOS Tuning Techniques for Retrograde Gas Condensate Reservoirs
Authors: Ibeh S. U. , Chubueze S. E.
Published: July 2016

PVT analysis is pertinent to field-wide development and optimization. This is because we need to know the over-all behavior of the fluid from reservoir through production and process facilities, down to the refinery. Its emergence as a separate discipline has been supported by the development of modern computer software that utilize EOS models for simulating experiments and representing fluid phase behaviours. PVT simulations are carried out to determine operating conditions that will maximize the surface liquid content and extend the production plateau duration at the lowest possible cost. In such simulations, Laboratory derived data are used to tune the EOS models and the results incorporated for reservoir simulation and studies. Obtaining a good match between EOS and laboratory data depends on data quality and for retrograde gas condensates, this can be very challenging due to their complicated phase behavior. Inadequate match results in computational errors and unrepresentative results when used in reservoir simulations and thus, jeopardize reservoir management decisions which are based on it.

The major contributions of this paper are-first,a review of critical issues and success factors in PVT analysis and its associated challenges. Second, methods for quality checking PVT data. Third, techniques for improving Lab – EOS match and their influence in PVT results.
Assessment of Factors Influencing Inflow Performance Relationships of Horizontal Oil Wells: A New Approach
Authors: Ogali O. I. , Ikiensikimama S. S. , Ajienka J. A.
Published: July 2016

Inflow Performance Relationships are used in evaluating the deliverability of a well in an oil and/or gas reservoir. Several factors influence the deliverability of a horizontal oil well; such as reservoir fluid properties, near wellbore conditions and reservoir relative permeabilities. Using dimensionless inflow performance relationships, the impacts of some reservoir rock, fluid and well properties on horizontal oil well performance were assessed. In this study, the concept of Concavity Index was used in assessing the impact of these factors. The Concavity Index is obtained from modelling the dIPR curves to capture the degree of curvature. In assessing the impact of these factors, the Change in Concavity Index is used. A factor is considered to have an insignificant impact if, for the range of values of the factor being assessed, the change in Concavity Index is less than. Absolute permeability had insignificant impact, for all the recovery factors assessed; whereas, wellbore skin had significant impact. For other factors assessed in this study, the impacts varied with the recovery factors. Therefore, the magnitude of the impact of these factors on horizontal oil well performance depends on the recovery factor at which the assessment is carried out. This new approach will improve horizontal well planning and management, and consequently economics.
Developing Renewable and Unconventional Energies as a Panacea to Falling Oil Price. How Possible in the Nigerian Case?
Authors: Osuagwu David
Published: July 2016

As a developing or underdeveloped country, a Nation backward in scientific and technological innovations, how can renewable and unconventional energies bridge the gap or ameliorate losses from oil and Gas energy derivatives? Globally, can renewable and unconventional sources of energy fittingly serve as an alternative or bridge the shortfall from conventional sources like coal, oil and gas? Though clean, green alternative energy is teeming all around the world – Solar, wind, Biomass, Hydroelectric, tidal, wave power to mention a few. This paper evaluates the potentials of renewable and unconventional energies as an alternative source to oil and gas in Nigeria. It further examines the preparedness and capabilities of Nigeria to develop these energies in the face of her scientific and technological state. Granted that Nigeria is backward in science and technology, with concerted efforts and enabling government policies, technological breakthrough is achievable. It is incontrovertible that Nigeria has abundant human and natural resources. Her diverse people and huge population have produced talented professionals, excelling in other parts of the world. What the nation requires as a lunch-pad are sound management and government policies that are pragmatic, motivating, invigorating, strong in purpose and discipline. The natural resources are visible all over the place in Nigeria. The non-renewable and conventional energies which have been the main stay of Nigeria's economy are in crisis. What other choice does the nation have? The renewable and unconventional energies like Solar, Wind, Hydroelectric, Piezoelectric, Helioculture, Salt water power, ocean thermal energy conversion, Human sewage, Hot rock power, Evaporative energy, vortex induced vibrations, Mining the moon and even space-based solar power are begging to be harnessed. How prepared are we as a Nation to develop these renewable energies? The level of preparedness for scientific and technological development is still very low. Research and production are still at minimal level. Budgets for scientific research over the years have been an aberration. The will and zeal to innovate appears to be absent. The paper concludes that there is real energy crisis in Nigeria and the world generally and there is a wakeup call to this militating economic cancer. The paper recommended that renewable and unconventional energy sources should be explored and assiduously exploited as a panacea for the declining conventional energy sources.
Optimizing Well Design and Delivery for Wellbore Stability Management by Minimizing Subsurface Uncertainties
Authors: Odagme Baridor S. , Dosunmu Adewale , Oriji Boniface A. , Fekete Paul
Published: July 2016

Modeling instability in shales is pertinent to managing risk and uncertainty associated with drilling troublesome formations. Design parameter such as Unconfined Compressive Stress (UCS) is usually estimated from sonic or other porosity logs and calibrated with results of triaxial test from core samples. However, sonic logs may not be available for some wells, making UCS estimation difficult thereby increasing uncertainty. In this work, a compositional approach was used to evaluate UCS and the Volume of Shale (Vsh) of the rock was modelled from the spectral gamma ray (SGR) or gamma spectrometry as a measure of shaliness instead of the gamma ray. This is because the sandstone sequences as obtained in Niger Delta fields contain some non radiactive clay which gamma ray log may not delinate clearly. Subsurface geological issues like bedding plane and faults were also modelled and the estimated UCS at various intervals and lithologies were calibrated with offset well data. Field results showed consistent and reliable estimates of UCS in the absence of Sonic logs with a percentage error of ± 0.0208. The predicted safe drilling mud weights must be accompanied by good drilling practice and proper hole cleaning. ECD and fracture gradient issues were captured to prevent excessive loss circulation. Instability risk were minimized and the case study well presented showed consistent result.
WRFM Technical Data Management - An Enabler for Effective WRFM Value Loop Excellence
Authors: Kingsley Iheajemu , Thomson Attah , Kalu Igban , Babatunde Adeniran
Published: July 2016

Most operating units, including Shell Companies in Nigeria have faced increased pressure to provide quality information timely and more efficiently for effective business decision-making. One of the most fundamental assets of a company is understanding the value of data and the knowledge it creates.

Data quality improvement involves several factors, they include, but are not limited to: a technical understanding of data source;understanding data gathering processes; and having people with well-defined roles, responsibilities, and authority to develop a culture that supports data quality improvement. As such, the majority of assets in different countries need a consistent and standardised approach in managing their Wells, Reservoir, and Facility Management (WRFM) technical data.

The WRFM value loop is a conveyor belt of data into opportunities that are executed to add production and reserves, therfore all the segments of the value loop need to be effective. Data management as an integral part of the value loop is one of the mandatory minimum requirements set out to support WRFM excellence.

The need for quality data which has led to data standardisation efforts enforcing rigorous plans within WRFM assets has to a large extent tackled lingering data issues ranging from;Technical data inaccessibilityDiscipline data ownership issuesData quality and inconsistency andLost time spent on data search, revalidation and rework, etc.

A series of Technical Data Management (TDM) initiatives were implemented to include the use of; Data Atlas, standard WRFM Technical Data Management plan which supports the WRFM programme by defining data stores, retrieval workflows, data quality requirements, roles and easy access to all WRFM critical data and the WRFM Critical Data Catalog, among others.

These technical data management initiatives have been effective as is evident in Data Management ratings and scores at recently concluded external WRFM assessments thereby supporting five Shell Petroleum Development Company (SPDC) assets to achieve world-class status passing minimum standards.

Also, generally in Shell Companies in Nigeria, proper management of access control measures, data security classification, data archiving and retrieving yielded reduced time spent by data users over the years by 37%, enabling additional barrels with efficiency gains and timely decision making.

This paper therefore highlights the benefits of TDM in WRFM processes, as a key element in the WRFM value loop, providing trusted data at the fingertips of engineers and geoscientists alike.
Case Study of Unitisation and Joint Development of Straddle Fields in Nigeria
Authors: Egba Amba Ndoma , Bekee Emmanuel , Oriaifo Maynard , Dosunmu Adewale
Published: July 2016

Hydrocarbon accumulations more often than not straddle two or more license areas or concessions and sometimes, international boundaries. Unitisation is a process whereby petroleum reservoirs (fields) straddling concession boundaries are developed and exploited as a unit using a single operator (the Unit Operator) and common production facilities under a signed agreement (Unitisation Agreement), by the holders of the respective concessions. The objective is to maximise economic recovery of producible hydrocarbon. In Nigeria, the enabling law that gives legal backing for unitisation is the Petroleum (Drilling & Production) Regulation 1969, Section 47, as amended and the 2008 Unitization Guidelines by the Department of Petroleum Resources (DPR). These laws are made pursuant to the powers conferred on the Minister of Petroleum Resources under Section 9 of the Petroleum Act (CAP 350) laws of the Federation of Nigeria 1990.

One of the major milestones in the unitization process is the signing of the unitization and unit operating agreement (UUOA). The UUOA specifies how the straddle field is to be operated and defines tract participation (the equity interest, assigned to each Concession in the Unit). As at today, over seventy (70) straddle fields have been identified in Nigeria but not up to five (5) UUOA agreements have been executed. Issues ranging from correct interpretation of Regulation 47,recognizing unitization of straddling and non-straddling reservoirs, to single and combined provisional tract participation (PTP) for oil and gas, economic consideration & contractual disputes, fiscal terms, Redetermination, Reference dates, appointment of unit operator, funding, divestment, political and personal interest etcetera, have made unitization of straddle fields elusive for many years thereby locking down billions of barrels of reserves. This undoubtedly, is not in the national Interest, especially when the Country is striving to increase the Nation's reserves base from the current 36.24 barrels of oil to about 40 billion barrels and the daily production output of 2.5 million bopd to 4.0 Million bopd by year 2020.

This paper therefore examines the synopsis of unitisation and joint development of straddle fields in Nigeria, the concerns and pitfalls arising thereof. The evaluation of some selected cases is also made to ascertain the effect of delay from Government objectives of reserves addition and production along with suggestions for future policy formulations.
Modelling Wellbore Stability by Chemical Method in Niger Delta: A Review
Authors: Okafor I. S. , Joel O. F. , Iyuke S. E. , Ndubuisi C. E.
Published: July 2016

Drilling through shale formation can be challenging and sometimes results in wellbore instability problems due to the reaction between hydrophilic shale and drilling fluids. The typical low permeability of shale, the presence of ions and charged surface of the constituent clay are factors which makes the problem of wellbore instability very complex despite efforts dedicated to the study by researchers. The study of wellbore stability in shale is quite important because 75% of all formation drilled worldwide are shale formations and 90% of all wellbore instability problems occur in shale formations costing the industry more than $1 billion USD/year (Chenevert, 2002; Zeynali, 2012); the lost time due to this challenge also account for over 40% of all drilling related non-productive time (Zhang et al, 2009) and these instabilities are responsible for 10-20% of the total drilling cost. A solution through this challenge is critical to the sustenance of the investment made by operating companies in the oil and gas industry. This will drastically reduce drilling cost, completion and workover cost as well as the accompanying downtime involved. It will also improve the net present value of operating company in the industry. Basically wellbore instability occurs when the mechanical stress induced by drilling into the formation exceeds the formation rock strength. Chemical interactions between the drilling mud and the in-situ shale affect the in-situ stress state of the formation hence the stability of the formation. Geo-mechanical models have been designed to tackle mechanical wellbore instability in the Niger Delta the challenge therefore is a chemical solution to the wellbore instability problems of the region. Oil-based muds have been known to overcome wellbore stability problems, but disposal challenges and environmental concerns have led to infrequent use. The challenge therefore is to formulate an environmentally friendly drilling mud having the inhibitive properties to tackle the wellbore instability challenges. This paper presents a review of studies carried out to characterize the mineralogy of shales and the salinity distribution of formation water in the Niger Delta depobelts with a view of designing a "balanced-activity" drilling fluid to help stabilize the formation during drilling. Results obtained from the reviewed researches showed that shale mineralogy characterization and formation water salinity distribution is critical in designing a balanced-activity drilling mud that can effectively tackle the problems of wellbore instability.
A Systematic Approach to Intelligent Well Performance Modelling Using IPM Suite
Authors: Edih Michael , Nnanna Erasmus , Nwankwo Cosmas
Published: July 2016

Intelligent well technology use Inflow Control Devices (ICDs), Inflow Control Valves (ICVs), and measurement devices that provide opportunity for monitoring and control of production from different reservoirs from the same wellbore. The common value drivers for the deployment of intelligent wells include reduction in well count during field development; accelerated ultimate recovery (UR); and accelerated production. Efficient and accurate modelling is therefore critical for the realisation of the full benefits of intelligent wells in addition to other technologies like the use of geochemical finger printing.

In this paper, a simple workflow for modelling the performance of intelligent wells is presented. This workflow identifies the limitation of current standalone PROSPER model and provides a window to easily match the model to actual well test results, providing multiple calibration points and ensuring full utilisation of the data made available by the intelligent well accessories like the permanent downhole guage and downhole flowmeter. The workflow has been applied to carryout nodal analysis of both oil and gas completions in the Niger Delta, Nigeria.

The modelling workflow is divided into two (2) aspects – the inflow modeling, for each inflow zone, and the outflow modelling that captures the commingled production. The commngled outflow model is used to generate the lift table for the GAP model.

The well deliverability and PQ curves are generated and plotted using the Openserver utility in IPM, which can be used also to view the performance of the model against validated well test results.

Results of applying the workflow to two case studies in the Niger Delta were analysed. The model was used to predict the expected performance of the wells at different surface choke sizes and ICV settings. The model results (flow rate, flowing tubing head pressures, flowing bottomhole pressures) matched closely (with maximum of 10% deviation) with the actual measured results, confirming the accuracy of the recommended workflow.
Reservoir Properties Distributions in A1000 Geologic Models for Optimal Drainage, Onshore Niger Delta
Authors: Afuye Taiwo
Published: July 2016

The interpretation of depositional environment and the reservoir properties, properties modeling and property prediction for field development planning are characterised by subsurface uncertainties. There are reduced wells data and absence of core data for the derivation of estimates of subsurface parameters; which form input to the process of populating trends to constrain the extrapolation of properties which increase these uncertainties.

An Areal Geological Concept; 2D Trends (Probability) Map of the A1000 Reservoir was built based on the geological interpretation of the depositional environments as interpreted from the well logs, provides areal coverage for the models. The 2D Trends Map generated was used to guide the extrapolation of reservoir properties away from well control/coverage. The Stochastic approach uses Sequential Indicator Simulation (SIS) and Sequential Gaussian Simulation (SGS) algorithms in PETREL Modeling software for building the facies and petrophysical models respectively and as well, incorporating this 2D Trends Map and tested Modeling parameters, such as variograms, kriging, cell sizes, zones, and to determine which set of parameters ultimately produced the most geologically reasonable model of the A1000 reservoir thus minimising the subsurface uncertainties.

The results of the properties models show that regions showing good facies, higher porosity, higher permeability, lower shale volume, lower water saturation values of the A1000 reservoir as optimal location for development wells placement from the static modeling perspective.

Quality Check Tests show that reservoir properties models built are consistent and honoured the geological interpretation of the depositional environments. This approach will enable optimal development well placement, Stock Tank Oil Initially in Place (STOIIP) estimate and eventually leading to successful dynamic Modeling of the reservoir.
Usan Field: Maximizing Production from New Drillwells in a Hydraulically Constrained Deepwater Subsea System Using IPM suite
Authors: Oguchi Arinze , Remi-John Babatunde , Okonkwo George
Published: July 2016

Usan, a deepwater field located offshore of Nigeria, commenced production in February 2012 with development drilling to be completed in 2016.

The field has 2 subsea flowline loops with 4 risers giving the flexibility to flow wells through two different risers. Due to the constrained flowline capacity, optimization of well routing and drillwell sequencing became critical to sustain the remaining drillwell campaign while maximizing base production and incremental uplift. The adopted approach by the Production and Reservoir Engineering teams was to utilize the Integrated Production Modelling (IPM) software suite (PROSPER, GAP & RESOLVE) to ensure optimal well mix and flow stability.

A systematic approach of continuously testing various routing scenarios of wells within the different production loops was applied to minimize production back out loss due to system hydraulics during the streaming of new drillwells. Different ramp-up scenarios were also tested for the new wells to minimize back-out on base wells. Due to variations in fluid properties, reservoir pressures, depletion strategies and loopline distance, the system needs to be re-evaluated frequently. With over 50 routing sensitivities assessed at each evaluation, identifying and implementing the optimal routing/configuration became critical.

Production optimization using the IPM model has led to higher FPSO incremental rates from new drillwells due to optimized well routing within the production risers. This has also helped to sustain the ongoing drilling campaign in the Usan field and improved the economics of the overall project.

This paper describes how IPM software was used to maximize incremental production from new drillwells.
Usan Field: Managing Gas Injection at Mechanical Seal Capacity
Authors: Oguchi Arinze , Okonkwo George , Sarumi Oluwatoyin
Published: July 2016

Usan is a highly-compartmentalized deepwater field offshore Nigeria with both structural and stratigraphic barriers across and within the compartments. The reservoirs were at their mechanical seal capacity based upon evaluation of reservoir and leak-off pressure trends. This complicates gas injection and pressure maintenance in the Usan field.

Due to the lack of gas export channels, gas injection was adopted as part of the development plan for the field in addition to water injection. During the first 18 months of production, less than 40% of produced gas was reinjected due to reservoir pressure/leak-off constraints.

A gas injection strategy was developed based on a number of uncertainties which included actual crestal depth, fracture pressures, and communication within and across compartments. To maintain or increase gas injection, the team needed to establish reliable crestal depths for each compartment, define safe injection pressure for each injector, and effectively monitor the pressure response of the reservoirs to ongoing gas injection.

A novel approach was used in better determination of the crests using fracture and fluid gradients. Safe injection pressures were based on dynamic injection pressures rather than static reservoir pressure. With these estimated crest depths and fracture pressures for the gas injection compartments, volume-depth curves were used to determine gas column height and safe injection pressures were calculated for each gas injector. Due to the mechanical seal integrity concerns, a monitoring system was developed to avoid the risk of fracturing the reservoir with continued injection. The surveillance strategy utilizes real-time flowing well pressures, short duration shut-in pressures, and evergreen volume-depth curves.

Ultimately, managing reservoir pressure levels and trends in each compartment allowed for increase in overall gas injection in comparison to previous methodology. A 30% increase in gas injection rate was immediately achieved. Optimal gas injection has also been maintained resulting in improved oil recovery.

This paper focuses on the methodology of determining/applying safe gas injection targets and maximizing oil recovery within the known constraints and uncertainties.
Fiscal Policies in Oil and Gas Sector: Quantitative Assessment of Impact of Royalty Terms on Proved Reserves Estimation
Authors: Ikwan Ukauku , Dosunmu Adewale , Iledare Wumi
Published: July 2016

Petroleum Fiscal Systems refer to the arrangements between a host government and an oil and gas exploration and production company to explore, develop and produce hydrocarbons. Royalty term is a key element of any petroleum fiscal policy and it could be fixed-by-terrain or sliding by volume and petroleum price. Nigeria like most countries operates a fixed-by-terrain royalty system. The defects of such a system include negligence of the size of the firm and the price of hydrocarbon in determining royalty terms. This is attended by negative shock on profitability of small firms and their operations on the one hand and the take statistics of the host government on the other. For example marginal field operators find it difficult to operate under fixed-by-terrain royalty system. All previous investigators on fiscal terms have focused quantitative evaluation on impact of fiscal terms on profitability indicators vis-à -vis impact on government and contractor take statistics without extending to proved reserves impact. This paper fills this gap.

This paper focuses investigation on quantitative analysis of impact of variable and fixed-by-terrain royalty terms on proved reserves using an archetypal onshore producing oil and gas asset, existing royalty term in Nigeria as well as the archetypal sliding royalty terms in Nigerian 2012 draft Petroleum Industry Bill. A proved reserves economic spreadsheet model based on SPE Petroleum Resource Management System (PRMS), sliding and fixed royalty systems was developed and used for the study.

The investigation shows that with two-tier sliding royalty system (based on volume and oil or gas price) impact on proved reserves could be positive, in effect meaning less exposure on proved reserves in existing assets than under fixed royalty term. Also under a period of global low oil price like in late 2014 to early 2016 where oil price has dropped by close to 250%, the firm may have positive effect on proved reserves due to reduced royalty payment used in economic limit test analysis. These conclusions should guide policy makers and negotiators in deciding royalty terms in fiscal policy formulation.