bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimation of Bypassed Oil Volume after Waterflooding an Undersaturated Reservoir
Authors: Adeniyi Adekunle Tirimisiyu , Ezeagu Vera Ijeoma 
Published: August 2020

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 &gt; 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

Abstract
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 &lt;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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.