bluuebunny/crossref_metadata_2025 huggingface dataset:
Investigating the Correlation between Water Saturation obtained from Cased-Hole Saturation Tool Measurements and Produced Water Cut in Strong Water Drive Reservoirs
Authors: Pius Timothy O. , Olamigoke Olugbenga
Published: August 2020

The correlation between the produced water cut and average water saturation around the perforation obtained from Cased-Hole Saturation Tool (CHST) measurements is evaluated in this paper. The motivation for this study is to enable significant financial savings which would accrue by the need for less CHST logging runs for effective Reservoir Fluids Management provided average water saturation can be quantified in terms of produced water cut, the water perforation coverage and the wellbore completion string parameters such as perforation thickness, and deviation angle.

Average water saturation and perforation water coverage, was determined by analyzing CHST logs block by block obtained using CHST tools in two different petroleum provinces (Nigeria Joint Venture Area and North Sea Basin). For each well logged, well test data or Production Logging Tool data, wellbore deviation survey and the completion schematic were obtained. The datasets from each region were split in two categories – well shut-in for less than four months prior to CHST log measurements and wells shut-in for more than 4 months. Regression analysis was used to investigate the correlation between CHST log determined parameters and other flowing and static wellbore parameters for wells without any history of damage or complex water production mechanisms.

The results obtained indicate that for wells in the Niger Delta with large perforation intervals (> 30 ft), produced water cut strongly correlates with average water saturation while for wells in the North Sea Basin with short perforation intervals (10 - 30ft) the average water saturation correlates strongly with both water cut and the perforation interval thickness. It was apparent that for the wells shut-in for periods exceeding four months no empirical relationships could be established. Heterogeneity in petrophysical property distribution and borehole reinvasion are suspected to be responsible for deviation from the correlation between produced water cut and average water saturation.
The Application of Investigative Workflows for Sour Field Mitigation and Remediation
Authors: Harper Christopher , Michael Nnochiri , Yan Zheng , Victor Okowi , Bamisebi Adetloye
Published: August 2020

Reservoir souring is simply defined as the predicted or observed increase in production of sulphide in oil, water or gas phase. The potential causes are far less simply defined, and can, in many cases, lead to a significant disruption to operations through concerns over HS&E, integrity and process efficiency. The consequences of sour production can be far reaching, and almost always expensive, perhaps to the point of making a field un-economical to produce.

One of the reasons for this is that, in many cases the response to souring is to mitigate, long term and short term, the consequences of souring, rather than the cause of souring. This paper examines the application of both high level and detailed investigation workflows which have led to significant improvements in understanding both the risks associated with souring and the most techno-economically feasible long term and short term mitigations of both causes and effects.

The aim of the workflow is to define causes and develop solutions to either mitigate souring and/or the effects of souring, maximising the techno-economic benefit to the operator and reducing HS&E risks as much as possible. The workflows themselves are phased and flexible, they aim to examine pre-existing data, examine their validity, and/or collect new data to identify the probable causes of souring in each specific case. Once the cause(s) have been defined it then becomes possible to estimate worst case souring potential and integrity threat based upon biochemical and geochemical interactions, phase behaviours and the physical condtions for either microbiological and/or non-microbiological throughout the system.

This approach has been applied numerous times to great effect in sub-sahran Africa, North America and Europe.
Interpretation of 3D Seismic Data for Prospectivity of Underexplored Deep Formations in Pateke Field, Niger Delta Basin, Nigeria
Authors: Nwike I. S. , Onwuemesi A. G. , Nwozor K. K. , Onuba L. N.
Published: August 2020

Overlooked prospects and underexplored fields in the Niger Delta Basin continue to attract the attention of many stakeholders in the industry as the quest to achieve the national 40 billion barrels oil reserve target continues to gain momentum. A key area of interest is that many wells drilled earlier in the basin were limitedlargely by technology from probing deeper formations. With the availability of 3D seismic data, improved subsurface knowledge, more efficient interpretation tools and skills, this study reevaluated the hydrocarbon potentials of the economically strategic ‘Pateke’ field in the Coastal Swamp Depobelt where the deepest well was drilled to a total depth of 8950 feet (2728 meters). Thereevaluation approach involved high precision fault and horizon mapping, seismic attribute extraction and analysis using the Petrel platform. The interpretation shows the structural framework of the field to be constituted by five faults with two major faults trending east – west and northwest – southeast respectively, thus dividing the field into three fault blocks. Integration of Root Mean Square (RMS) Amplitude, Envelope and Sweetness seismic volume attributes suggest probable hydrocarbon accumulations within the fault blocksthat lie far beneath the reach of the present wells in the field. The implication of this result is that the full potentials of ‘Pateke’ field are yet to be achieved considering the positive indications of economically recoverable hydrocarbons in the deeper sections of the field.
Determination of Optimal Well Location in Bounded Reservoirs Using the Dimensionless Pressure Derivative
Authors: Ojah Michael , Enuma Emumena , Onah Collins , Prince Oduh , Adewole Steve
Published: August 2020

When a reservoir is bounded, well productivity is affected in the long time according to the nature of the boundary. The length of time for oil production is strongly affected by well location with respect to the boundary, whether the boundaries are single, paired and vertical or paired and inclined. It therefore becomes important that well location is guided to achieve prolong oil production. The guide may be achieved from solution to a specific flow equation describing pressure distribution. The solution prescribes rates and well location for available reservoir system properties.

In this paper, dimensionless pressure derivatives of a vertical oil well are studied to search for optium well location that can guarantee satisfactory oil production without premature influence of the external boundaries. The external boundaries are sealing and are considered to be inclined. The solution to this dimensionless diffusivity equation is utilized. The derivatives are computed from the total dimensionless pressure expression summing all the image wells by superposition principle. The Python and Excel softwares were deployed to compute all the dimensionless pressures for the different well designs. Larger magnitudes of dimensionless pressure derivatives would indicate higher oil production for any well design and inclination of the sealing faults.

The optimum well location from the sealing faults is inversely proportional to the inclined angles. This implies that nearer wells to faults produce optimally at a given time of production. Furthermore, the relationship between well distance and productivity has no maximum or minimum points. Therefore there is no particular optimum location distance from the faults for optimum productivity. Optimum well location for sealing boundaries depends on many factors, such as production profile, well design, faults angle, fluid type and lease size. Furthermore, it was also observed that the wellbore radius has no significant effect on the dimensionless pressure derivative, optimum well location and the optimum time of production.
Effects of Additive Concentrations on Cement Rheology at Different Temperature Conditions
Authors: Ikpeka Princewill , Benedict Ugochukwu , Utojiuba Davida , Odo Jude , Uzuegbu Godson
Published: August 2020

Previous studies suggest that the rheology of cement slurries used during oil well cementing operations is an explicit function of temperature, additive type & concentration and cement grade. This study analyzes the effect of these factors on a water based mud (WBM). 27 experiments were conducted by varying three additive concentrations; retarders, fluid loss additives and dispersants. Shear rate and stress were then experimentally determined at varying temperature and concentration, while the plastic viscosity (PV) and yield point (YP) were determined analytically. The slurries were conditioned as set out in API RP 10B-2. Linear regression was used to build models describing the effect of temperature and additive concentration on PV and YP of the cement slurry. Results from the analysis reveal that for a temperature increase of 125% and Retarder concentration increase of 200%, there were significant decline in PV (-41%) and YP (-44%). Whereas increasing the Fluid loss additive by 100% caused a significant increase in YP (+51%) and relatively insignificant increase in PV (+4.4%). This study concludes that the coupled effect of increasing temperature and retarder concentrations of cement slurries has a significant negative impact on both the YP and PV.
Optimized Salinity Water Flooding as an Improved Oil Recovery IOR Scheme in the Niger Delta
Authors: Alaigba David , Oduwa Onaiwu , Ohenhen Ikponmwosa , Olafuyi Olalekan
Published: August 2020

Following on from the work by Tang and Morrow in 1998, enormous progress has been made in the development of low salinity water flooding for improved oil recovery, (IOR). This paper has assessed the applicability of modified salinity as an IOR scheme in the Niger Delta. A laboratory approach which entailed the use of crude oil, brine and core plugs from fields X and Z located in the Niger Delta was adopted. Several options were assessed: progressive dilution of the injected brine, variation of concentration of divalent cations in the injection fluid, high salinity flooding followed by low salinity flooding (HSF, LSF) and variation of low salinity slug size. The results obtained are very promising as additional recoveries in the order of +5% to 21% were obtained from this work. Based on the promising results of this on-going research, recommendations on future improvements were also outlined.
Experimental Characterization of Palm Kernel Shell as Wellbore Strengthening Material for Depleted and Loss Circulation Zones
Authors: Emmanuel Ayodele , Dosunmu Adewale
Published: August 2020

With a continued growth in the discovering of new reserves at deeper depths in mature fields, drilling through the depleted and already producing zones is already posing a loss circulation problem as well as other wellbore instability problems such as stuck pipe. Considering the cost of loss circulation materials and its effectiveness the need to source materials locally for LCMs becomes imperative. This research work investigated palm kernel shell as a local material to be used as loss circulation material, the processed palm kernel shell was sieved into different particle sizes and added in various mass ratio to the formulated mud. The mud weight, filtration test and permeability plugging test was done to experimentally characterize the mud based on its effectiveness as a loss circulation material. Palm kernel shell with blends of other industry loss circulation material was also considered to ascertain the blended LCMs effectiveness as compared to the palm kernel shell mud samples. From the experiments conducted, the mud weight of palm kernel shell mud samples ranges from 11ppg to 11.4ppg in different particle size distribution. The total filtrate loss and the filter cake thickness ranges between 5.0ml to 8.6ml and 1mm/32-inch to 2mm/32-inch respectively. The permeability plugging test of the Palm kernel shell mud samples has a range of total filtrate volume of 8.9 ml to 11ml, as well as filter cake thickness of 3mm/16-inch to 4.5mm/16-inch. In a comparative analysis, the blend LCMs, i.e. the palm kernel shell and Mica, palm kernel shell and graphite have a better sealing and filtrate loss properties than the palm kernel shell mud samples. It is therefore recommended that more research should be carried out on the blends of palm kernel shell and other LCMs as it will be cost effective when compared to the imported LCMs.
The Nigeria Gas Landscape: Implications for Economic Development
Authors: Gbakon Kaase , Ojaraida Lolo
Published: August 2020

The gas supply system in Nigeria is today skewed to favour exports over domestic utilization, thus leaving unfulfilled what have always been the twin objectives of Nigeria’s gas policies–robust foreign exchange earner and stimulation of the national economy. So far as this review has shown, neither of these objectives has been achieved – yet. FG earnings from export oriented NLNG at $43Billion in the last twenty years is about the same quantum that is on average distributed annually to the states via the Federal Allocation Accounts Committee (FAAC). While domestic gas supply is sufficient to generate only 16W of power per Capita – the lowest in a peer comparison of select African countries.

However, it has not always been the case that gas enjoyed a prime focus in the energy policy framework of Nigeria as it does today. Gas is receiving increasingly more attention as noted by deliberate policy actions taken at various times – the enactment of the NLNG fiscal act in 1989, introduction of the Associated Gas Framework Agreement (AGFA) provision in the PPTA in 1998, the incentives for gas utilization projects in the Corporate Income Tax Act (CITA) introduced in 1998 and 1999, Gas Pricing policy of 2008, the National Gas Policy framework of 2016 and more recently the Flare Gas Regulations of 2018 – all targeted at the different components of the gas value chain – upstream production, market sector development, pricing, off-take, and related downstream utilization.

Global increase in natural gas utilization rides on the back of geopolitical dynamics such as climate change action, growth in emerging economies, and increased US shale gas production. Contextualizing Nigeria’s gas polices against the wider canvass of geopolitical concerns which include the interplay with Nigeria’s energy security suggests that Nigeria will have to take deliberate policy steps – from upstream gas fiscal terms reforms, through to pricing reform, project prioritization, strategic gas portfolio allocation to refocus effort on channelling gas to deliver a "harder domestic punch."
Raising the Sleeping Giants: Restarting of Alpha & Beta Fields World-Class WRFM Collaboration
Authors: Sa'ad Abdul-Wahab , Ayeni Olumide , Unukogbon Obaro , Nwosu Obiora , Imorame Imonitie
Published: August 2020

The importance of Wells, Reservoir, and Facility Management in the life of producing Oil and Gas assets cannot be overemphasized. Several authors in the past have highlighted the significant contributions WRFM practice and process have to the ultimate recovery of matured assets. WRFM serves as a stop-gap to redevelopment in areas of cash crunch, whereby active WRFM practice arrests severe natural decline in production. Onshore assets comprising of fields Alpha and Beta are operated by Shell Petroleum Development Company (SPDC). These assets have been operated for over 30 years, rising water cut & high gas-oil ratio production and facility downtime risks have impacted oil recovery. This work showcases the application of WRFM at the re-startup of production in these fields post shut-in for almost 5 years. Effective and deliberate application WRFM processes and practices woven together in the WRFM Plan not only ensure an efficient restart of the facility but the ability to ramp production while maintaining the intricate balance of good reservoir management. The paper will highlight the best WRFM practices which enabled the resumption of production at a lower water rate compared to when the field was shut and maintain this higher net oil for a prolonged time. Also highlighted are opportunity identification and implementation in-closed wells and effective collaboration across disciplines to ensure a safe and efficient restart of production facilities.
Estimating the Quantity of Recoverable Heat in a Geothermal Reservoir in Nigeria
Authors: Okeifufe Nnamdi Francis , Izuwa N. C. , Nwogu Ngozi
Published: August 2020

The quest for cleaner sources of energy in the world today has paved way for scientists and researchers to delve into renewable energies like the geothermal energy. Researches on the enormous potential that a geothermal reservoir could posses are currently underway. However, there is limited information on the quantity and quality of geothermal reserves in Nigeria. Extraction of this geothermal heat will improve power generation and the availability of scarce electricity in Nigeria. This work is aimed at using a mathematical model to estimate the quantity of recoverable heat by first estimating the total heat in place and then the heat losses associated with heat transfer in a wellbore. In this work, we were able to ascertain the heat in place as well as recoverable geothermal heat for geothermal regions in Nigeria having a temperature-at-a depth range of 50°C – 110°C and also a higher temperature-at-a depth range of 150°C – 250°C. Heat losses were considered for pipe tubings with 1 inch, 2 inches and, 3 inches diameter. A higher recoverable of 92% was gotten when the 1 inch pipe diameter was used. 87% and 76% recoverable were also gotten when the 2 inches and 3 inches diameters were used respectively. Nigeria has the potential of generating 74Megawatts of electricity from just one geothermal reservoir which could provide electricity for villages and small towns.
New Non-SARA-Based Correlations for Predicting Asphaltene Deposition
Authors: Sulaimon Aliyu Adebayo , Umar Abubakar Abubakar , Sulaimon Abdul-Azeez Oladimeji , Masri Asiah Nusaibah , Bello Kelani Olafinhan
Published: August 2020

Asphaltene deposition constitutes a major flow assurance challenge during oil production. Several attempts have been made to predict asphaltene stability using SARA analysis, which is usually expensive and time-consuming. Therefore, we have developed new SARA-independent correlations for the colloidal instability index (CII) and the refractive index (RI) as functions of oil density. The new density-based CII or DBCII is proven to be reliable with an average absolute relative error (AARE) of 0.1428, standard deviation (SD) of 0.1902 and a correlation coefficient R2 of 0.9520. Similarly, density-based RI or DBRI has been validated with an AARE of 0.0037 and SD of 0.0044. Two new deposition envelops have been developed with different criteria. The stable regions are characterized by DBCII lesser than 1.1 and DBRI greater than 1.525 while the unstable zones are defined when DBCII is greater than 1.8 and DBRI lesser than 1.503. The metastable region is identified within the limits of stable and unstable criteria. Comparative analyses have shown that the new correlations are simpler, cheaper and more accurate than the existing SARA-fractions-dependent-RI correlation and molecular-weight-dependent CII correlation.
Model for Estimating Optimum Hydraulic Fracture Geometry in Gas Condensate Reservoir
Authors: Odo Jude Emeka , Ikpeka Princewill Maduabuchi , Okereke Ndubuisi Uchechukwu , Odo Blessing Chidinma , Idika Uduma Uduma , Ofoegbu Daniel Chukwuebuka
Published: August 2020

A new analytical model for optimizing hydraulic fracture conductivity has been proposed by modifying the model developed by a researcher using the formula obtained from classical 2D Perkins-Kern-Nordgren (PKN) model as a function of proppant viscosity and the young modulus (rock compaction). This study shows that fracture conductivity depends on penetration ratio and fracture conductivity decreases as penetration ratio increases and this is due to the increase in overburden pressure of the rock and viscosity of the proppant fluid and this lead to reduction in productivity. It was proposed that productivity can be increased by increasing the fracture pressure and the viscosity of the fluid depending on the type of formation.
Estimation of Bypassed Oil Volume after Waterflooding an Undersaturated Reservoir
Authors: Adeniyi Adekunle Tirimisiyu , Ezeagu Vera Ijeoma
Published: August 2020

A significant amount of hydrocarbon ends up unrecovered due to poor sweep efficiency, after water flooding, with oil recovery factor typically less than 50%. Residual oil saturation varies depending on lithology, pore size distribution, permeability, Wettability, fluid characteristics, recovery method, and production scheme. The reservoir history showed that oil initially in place was 95.76 MMSTB, dissolved gas volume of 83.79 BSCF and 266.22 MMSTB of water. Oil production rate was 10,000 STB/D, cumulative oil produced was 72.73 MMSTB, and cumulative water produced was 132.91 MMSTB. A cumulative of 65.74 MMSTB of water was injected a daily rate of 3000 BW/D. The initial reservoir pressure was 4912 psia and bubble point pressure of 3592 psia. Water breakthrough occurred after the 7th year of continuous water injection. The simulation result showed that 22.97 MMSTB was bypassed (23.9 % of oil initially in place).
Analysis of Petrophysical Properties and Evaluation of Gas Flood Possibilities for Chinese Tight Sandstone Using Pore Network Modelling
Authors: Lawal Rasaq
Published: August 2020

Hydrocarbon recovery from conventional resources has seen a great decline over the years, with the most recently discovered reservoir being from unconventional resources. Unconventional resources (such as tight oil, shale gas, tight gas, etc.) have contributed immensely towards the world energy provision and continual technical development to best understand and predict the best recovery method that is affordable has been the oil and gas industry focus. Relative permeabilities and capillary pressures of tight sandstone have proven to be one of the governing parameters important in understanding fluid flow through the tight reservoirs and estimating the recoverable hydrocarbon. Estimation of these petrophysical properties (especially three-phase properties) is tedious and costly using convention experimental method and thus the advent of pore network modeling which offers competitive alternatives in terms of accuracy, time, and cost.

In this paper, we present the use of pore network modeling to analyze the petrophysical properties and evaluate possibilities of gas injection for the Chinese tight sandstone sample. Two segmented micro-CT images S5 and S9 were obtained from a Chinese tight sandstone reservoir and the network extraction was carried out using Heriot-Watt university in-house PAT software. The pore network model takes as input the extracted network of the two tight sandstone samples and simulations were carried out to determine and analyze the two-phase petrophysical properties of S5 and S9 considering different wettability scenarios. Three-phase displacement was also carried out for S9 to estimate petrophysical properties for the gas flooding process.

The comparison of mercury drainage curve and single-phase properties (i.e. porosity and permeability) of the sample S9 from an experiment with network model derived ones show close similarity in the porosity and permeability value. Additionally, sensitivity for the three-phase displacement of the sample S9 has been conducted on residual oil saturation for different wettability conditions, different target water flood saturation, and spreading and non-spreading oil. For spreading oil, which is more desirable for enhanced oil recovery, residual oil decreases with decreasing target waterflood saturation. This shows that the pore network model can be successfully used to analyze petrophysical properties of corresponding tight sandstone formation as well as predicts the most suitable flooding mechanism.
Development and Prediction of Cavitation in Centrifugal Pumps using Industrial Internet of Things Technology
Authors: Ejimuda Chinonyelum
Published: August 2020

The enormous cost of downtime and safety hazards caused by failure of pumps due to cavitation are widespread in the oil and gas industry - upstream, midstream and downstream sectors. Current devices and technologies used to address cavitation are either used after it occurs or very expensive to procure. A cheaper and more efficient system was proposed, capable of addressing cavitation in centrifugal pumps. A test rig of the centrifugal pump was constructed, integrated and programmed the sensors using C++ and Arduino microcontroller. Subsequently, the telemetry data from the sensors and predicted the likelihood of cavitation or no cavitation by varying the ball valve angles were analyzed. Although preliminary results are very promising from current methodology, but currently working on using python and machine learning techniques. It is expected that these and more will further improve pump cavitation prediction accuracy.
Gas Rate-Decline Type Curve Analysis Using a Semi-analytical Model
Authors: Mienzan Fabiola Kpovole , Asumadu Derrick Yeboah
Published: August 2020

The diffusivity equation for a real gas flow through porous media is nonlinear due to the variations of fluid properties with pressure. Consequently, several approaches have been presented in the literature to account for these variations. Unfortunately, while some of these approaches are heavily based on iterative schemes, others are based on functional relations of fluid properties and pressure.

In this paper, we present a new set of rate-decline type curves to analyze and predict gas well performance. The rate-decline type curves have been developed based on a semi-analytical model. The variations of gas properties have been accounted for in a drawdown parameter. Results based on numerical and field data show that the proposed gas well rate-decline type curves provide at least two advantages over the existing methods: First, the gas properties are relatively easily handled via the drawdown parameter; and, second, the original gas-in-place is determined without a time-consuming iterative scheme or functional relations of fluid properties with pressure.
Marginal Petroleum Field Profitability Analysis
Authors: Iheobi Christopher , Daramola Babalola , Alinnor Chidubem Martins , Okafor Ikechukwu Stanley
Published: August 2020

This paper evaluates the profitability of developing a Nigerian marginal oil field in a low oil price environment. The undeveloped asset is located offshore, and remains undeveloped due to field size and remote location. Recent seismic interpretation suggested that the field could be larger than previous estimates, and this triggered re-evaluation for development. Subsurface and economic assessments were completed to evaluate the profitability of developing the field, and the NPV, profit to investment ratio, DCFR, payback period, and breakeven oil price indicators are presented.

The base case development scenario was unattractive, and additional sensitivities were completed to transform the marginal field into an attractive investment. The paper presents standard working practices used to evaluate the profitability of petroleum upstream assets. It also shows why economics is the bottom line of petroleum assets, recommends guidelines for selecting upstream investment projects and participating in petroleum licensing bid rounds, and illustrates how hydraulic fracturing has transformed low permeability oil fields in the USA into economic projects.
Multiphase Pressure Transient Analysis – Agbami Case Study
Authors: Fagbowore Olufisayo , Oyewole Anthony
Published: August 2020

Production performance of well assets changes as oil and gas assets mature leading to increased breakthrough of associated fluids (gas and/or water). Classic single-phase Pressure Transient Analysis (PTA) becomes limited with multiphase flow due to the underlying principles governing single phase flow resulting in errorneous interpretation results.

This paper presents the outcome of PTA interpetaion results for oil production wells that recently experienced water breakthrough to assess the value of performing post-breakthrough multiphase pressure transient analysis. Using field data, the results obtained from single-phase pressure transient analyses on buildups after breakthrough were inconsistent with results obtained prior to breakthrough. Multiphase pressure transient analyses were performed on the same post-breakthrough buildup data and the results were compared with the historical well and reservoir behaviors when the well was still in single phase and single-phase pressure transient was conducted. The results indicated excellent agreement in terms of well and reservoir properties between the buildups obtained during two-phase flow and those obtained during single phase flow when multiphase pressure transient analyses were performed on the buildups during two-phase flow.

The study also compared two multiphase pressure transient analysis methodologies: Perrine (1956) and Kamal-Pan (2010). Using field data, the results obtained from these two methodologies were observed to be consistent.

A key lesson learned during this study was the importance of the relative permeability data on the results of multiphase pressure transient analysis.
Developments in Gas-to-Liquids Technology Plant Optimisation for Efficient Utilisation of Flared Natural Gas in the Niger Delta
Authors: Ekwueme Stanley , Izuwa Chinedu , Odo Jude , Obibuike Ubanozie , Ohia Nnaemeka , Nwogu Ngozi
Published: August 2020

Research show that among GTL units, the syngas unit is the most costly. This is due to its high energy consumption, construction cost and complexity of configuration. Autothermal reforming (ATR) method which uses oxygen has been traditionally used in commercial GTL plants. This method is noted with high cost and high CO2 emissions. To optimize GTL plant, it is crucial to provide an alternative method that will reduce the total cost of the process, yield higher volumes of GTL liquids at minimal emissions. A new method is provided in this work. The method uses CO2 instead of O2 in a steam/CO2 reforming process as alternative to the autothermal reforming. The GTL plant is configured to utilize the CO2 in the raw natural gas stream and in the effluent (flue) gas, additional CO2 is gotten from natural gas processing onsite. The new GTL method is more cost effective, has potential for higher yields of desirable GTL products than the ATR syngas GTL method due to better H2/CO ratio.
Optimizing Hydrocarbon Recovery Through Rigless Conversion of Watered-Out Oil Well to Gas Producer: Obagi Field Case
Authors: Onwuchekwa Vincente , Onyema Uche , Onyeizugbe Samuel , Ohwo Augustine
Published: August 2020

Obagi is a mature onshore oil field in the Niger Delta discovered in 1964 which comprises of mainly oil-bearing reservoirs with some reservoirs having large gas caps. Over the years, significant oil production has taken place in the oil rims of the reservoirs with large gas caps. Time-lapse fluid saturation evaluation using openhole well logs and cased-hole saturation logs (CHSL) established flushed oil zones and the existence of significant remaining gas columns in two gas cap reservoirs.

Integrated reservoir studies identified watered-out wells that traverse these gas caps and are well placed to produce the gas zone with good clearance from the current water contact. In order to increase gas production potential from the Obagi Field at very low cost, a strategy of rigless intervention using coiled tubing for cement isolation and E-Line re-perforation to convert the watered-out oil wells to gas producers was adopted. Candidate wells for intervention were selected based on their location within the reservoirs, considering their proximity to the existing producers as well as the ease of connection to existing surface facilities.

An intervention was carried out on OB-P1 by isolating the existing perforations via coiled tubing by setting a plug in the tubing above the watered-out zone, performing a tubing punch and circulating cement in the annulus. An E-Line re-perforation was then performed shallower in the R1 reservoir gas cap with a ceramic screen installed for sand control.

A post intervention production test shows that OB-P1 has a gas production potential of > 250 kSm3/day (8.8 MMSCFD). This rate is constrained by damage (well still cleaning up) as well as mechanical skin due the completion type (ceramic sand screen) and the small effective wellbore diameter. Successful execution of three other planned conversion wells will replace, at least, one of the infill gas wells in the planned drilling sequence. This will result in a cost saving of about 65% of a new well.
The Impact of Fault Sealing and Transmissibility on Field Development. Case Study: Eureka Field Experience, Onshore Niger Delta
Authors: Amuboh Okiemute , Ahmed Suleiman , Enya Dolapo , Ibikunle Gbolade , Imorame Imonite , Obakhena Femi , Uyouko Ime , Dennar Lindar
Published: August 2020

Faults are subsurface entities in clastic fields that can influence the economic viability of a field at various stages. In Exploration, fault-seal behavior impacts prospect analyses, whilst in the Development stage, compartmentalization and fault transmissibility analyses impact Well placement, recovery and reserves estimation (Brem Et al; 2019). Accurate representation of structures -major and Intra-reservoir faults is a key requirement in any fault analysis and resulting impact. Hence, fault modeling-a key part of the structural modeling workflow in field development work cannot be over emphasized. The Eureka field is a high-pressure gas discovery asset in Shell 's operated acreage in onshore Niger delta. The field, which is currently in the mid development stage, comprises of stacked reservoirs with series of anticlinal dip assisted/fault bounded structure with minor faults. The potential compartmentalization of target reservoirs for development by intra-reservoir faults is the major uncertainty in the development of the Eureka field. This work aims to define the fault sealing properties of the intra reservoir faults and their impact on Eureka green field gas development.

The current development plan requires two or more Wells to be drilled to optimally develop the resource volumes in one reservoir (X2000) in the field. Mapping of each of the intra-reservoir faults from seismic and available log data were used to determine how well connected the segments separated by the faults are. Fault zone properties studied include fault throw/thickness, shale gauge ratio (SGR), fault zone permeability and transmissibility multiplier. The intra reservoir fault uncertainties were mitigated by building different realisations during the modeling process.

The intra-reservoir faults which are normal faults on the crest of the anticline in the study area have low SGRs and high permeabilities which indicates partial sealing capabilities. Also, the majority of the intra-reservoir faults have transmissibilities <1 which indicates partial fluid flow to partial seal. Partially sealed faults give rise to hydrocarbon movement through and along fault planes (Fagelnour Et al; 2018). Results of the fault zone properties were incorporated with fault transmissibility multiplier in a dynamic simulator and showed that one development Well can drain the gas bearing reservoir.
Conceptual Reservoir Development and Short-Term Forecasting Using Material Balance Based Integrated Asset Models and Neural Network Proxy Models
Authors: Nnamdi David
Published: August 2020

In the absence of 3D dynamic models for conceptual reservoir development and production forecasting, reservoir engineers are left with only one fallback option – the use of tank material balance models which may not fully capture the physics of flow in complex reservoir systems. In order to reasonably account for the varying factors that may affect production performance, a bit of ingenuity must be applied.

This paper describes the workflow involved in developing a comprehensive integrated asset model that is able to predict production performance under different reservoir configurations. First, using available petrophysical information, a method is presented to estimate recovery factor ranges and the corresponding residual saturations which is then used to constrain material balance models in prediction of ultimate recovery. The reservoir is then divided into drain sections with conceptualized target wells and the entire reservoir system is modeled as a connected multi-tank model with varying in-place volumes. The final steps involve building an integrated asset model consisting of wells and facility equipment and generating production forecasts.

In this study, key factors that impact the complex multi-tank model behavior and the resulting production forecasts are outlined. Boundaries were then set for these factors and multiple simulation runs generated for proxy model building using Neural Networks. However, it was noted that most of these factors were temporal and did not influence the overall cumulative production overtime. Hence for this study a fixed time period was used to evaluate uncertainties and generate forecast ranges.

This paper will be beneficial to reservoir engineers tasked with developing strategies for reservoir exploitation and forecasting pre-drill production profiles. It will be of special interest to engineers inclined to automation, script writing and the use of machine learning in subsurface analysis.
An Agile Quality Management Model for Optimizing Workover Operations in the Niger Delta
Authors: Kelvin Mogekwu , Erivwo Ochuko , Joseph Adams , Joshua Ozor , Ideh Matthew
Published: August 2020

Traditional quality management models and tools in recent times are giving way to integrated service quality models. These models check both equipment and personnel and operations optimization from the design stage, with one of the more recent innovations in this regard being the introduction of Agile Quality Management (AQM) in service quality operations.

AQM, in a project context, is concerned with having the right processes to ensure both effectiveness (quality product) and efficiency (quality project). This paper presents the development of an AQM model for well delivery operations and the tools and techniques with which it was deployed successfully in a workover operation in the Niger Delta.

AQM was deployed in six workover wells for OML 26 Asset as part of the Integrated project management of the well delivery process. The results of the model application in operations optimization are seen in the reduction of non-productive time (NPT) over the six-well campaign.
Assessment of Local Clay from Different Localities in the Southern Region of Nigeria for Drilling Mud Formulation
Authors: Ogofotha Godwin Oghenekeno , Nwonodi Roland Ifeanyi , Chemezie-Nwosu Harmony Agbonma
Published: August 2020

The present use of imported Bentonite in drilling for Oil and Gas wellbores is not favorable to the Nigerian Economy. This trend is expected to continue as drilling activities keep increasing. The large use and the high importation cost of Bentonite led to an attempt to find a suitable Nigerian local clay to serve as a substitute in order to reduce the cost of importation. This work focuses on the Assessment of local clay from different Localities in the Southern region of Nigeria to serve as a basic material for drilling fluids. This research shows by means of simple but relevant laboratory experiments the properties of locally formulated drilling fluids from these Localities in the Southern region of Nigeria and compared with imported Bentonite. Water-based mud was formulated from the locally available clay and their properties were determined and compared with those of the imported Bentonite. The results obtained showed that the density of locally formulated drilling fluids was almost up to that of Bentonite but a significant difference in the rheological properties was observed when compared with the Bentonite, which necessitated the beneficiation of locally formulated drilling fluids. Barite (BaSO4) and Caustic Soda (NaOH) were used to enhance the density and pH of the local fluids respectively. Xanthan Gum, a Viscosifier and Sodium Dodecyl Sulfate (SDS), which is a Surfactant, were used to control the rheology of the formulation. The conclusion drawn based on yield point/plastic viscosity ratio of less than or equal to 3 (YP/PV≤3) and minimum reading of Viscometer at 600RPM to be 30cp, shows that none of the locally formulated fluids without additive meet the API Specification but upon treatment with additives (beneficiation) at different concentration, some samples with local clay meet the API specification.
Infill Opportunities Validation for a Mature Niger Delta Reservoir: Lessons Learned and Best Practices
Authors: Ogbuagu Frank , Okani Nnamdi , Silpngarmlers Lynn , Strebelle Sebastien
Published: August 2020

Infill opportunity identification in a mature reservoir has some unique challenges because of the uncertainties in exact fluid front movement. These uncertainties are magnified for waterflood or gas-flood reservoirs.

The reservoir of interest is a saturated oil reservoir with 54 years of production history and under waterflood. The aim of this study was to validate with a dynamic simulation model, infill opportunities proposed from using a combination of map-based assessment and current reservoir production data.

High-resolution reservoir characterization was done to properly capture the different stratigraphic units in the reservoir. Insights from production and pressure behavior formed part of the input during the characterization phase. Results of the characterization step were used for earth modelling to generate a base case earth model for the reservoir used for history matching. Pro-cycling of the model was done during the history matching process, enabling the narrowing of fluid-in-place uncertainties during history matching. This resulted in a high-quality history-matched model that replicated over 80 percent of the fluid contact movement observed over the production life of the reservoir. This model was then utilized to validate two proposed infill opportunities in the reservoir.

A key lesson identified during the process is that the use of high-resolution reservoir characterization methods prior to the earth modelling stage ensures better tracking of fluid-front movement and better replicates observed historical data. Rapid cycling between the earth modeler and simulation engineer also delivers significant value, by helping to resolve history-matching challenges early on and ensuring alignment between the dynamic model and the static interpretation of the reservoir.
Advanced Mathematical Model for Prediction of Sand Production Rate: A Niger-Delta Case-Study
Authors: Okereke Ndubuisi , Ogbuka Vincent , Izuwa Nkemakolam , Kara Fuat , Nwogu Ngozi , Nwanwe Onyebuchi , Baba Yahaya , Kanshio Sunday , Odo Jude , Oguama Ifeanyi
Published: August 2020

The Tertiary Niger Delta Basin is dominated by a friable, loosely consolidated sandstone formations indicating the likelihood of sand production ocuuring during hydrocarbon production in such formations. The aim of this study was to develop a simple mechanistic model for predicting sand production rate (SPR) in Niger-Delta wells. Two basic criteria (static sanding criteria and the dynamic requirement for fluidization of the produced sand) were used in developing this model. A generic mechanistic model that incorporates the concept of dimensionless quantities associated with sand prediction was developed. In developing the model, loading factor, Reynolds Number, water cut and gas-liquid ratio, GLR were considered. A dimensionless sand production rate (SPR) correlation index was the output from the proposed model. Results indicated that every reservoir has a unique SPR correlation index which represents its propensity to produce sand or its sanding identity. Validation of the proposed model was conducted by comparing the model prediction results with field data. Model validation results showed an agreement between predicted with field results with an acceptable maximum deviation of less than 5% in for onshore wells. The proposed model was further compared to existing models and prediction results show that the proposed model gave better results than others especially when the boost factor, GLR is significantly high. The applications of this study range from field development plans and economics to reservoir management, down to general well completion design and strategies.
A Method of Estimating Reservoir Pressure using Drawdown Test Data
Authors: Idudje Henry , Adewole Steve
Published: August 2020

In conventional draw test analysis, initial reservoir pressure has to be known with precision to aid primarily to determine near wellbore skin. Furthermore, in old wells, the initial reservoir pressure has to be attained before drawdown. For very old wells and tight reservoirs therefore it would take painfuly long shutin time to eventually attain the initial reservoir pressure before drawdown. In largely depleted reservoirs, it may be impossible to actually attain the desired initial reservoir pressure even after a long shutin! Efforts at obtaining the initial reservoir pressure in all these cases would only yield the remaining reservoir pressure since fluid had been produced from the reservoir. On a semilog plot of flowing wellbore pressures versus time, it is not possible to estimate the reservoir pressure to even validate the recorded pressure before shutin.

In this paper, a procedure has been developed to overcome these challenges. The new method plots flowing wellbore pressures against dimensionless pressures on linear axes, assuming infinte-acting flow. The plot gives a straight line with intercept on the flowing wellbore pressure axis yielding the remaining reservoir pressure on extrapolation to dinensionless pressure of zero. Although, developed for horizontal well flow, it can be adapted for vertical well flow with minimal effort. Mathematical procedure employed is based on selection of relevant source and Green’s functions for a horizontal well during infinite-acting flow and assuming the well purely as a line source. A case pressure drawdown test selected for analysis using the method developed here yielded very close reservoir pressure compared to the reservoir being characterized.