bluuebunny/crossref_metadata_2025_split huggingface dataset:
Achieving & Sustaining Impeccable HSE Performance in Brown Field Operations Comes at a Cost OML26 Blazes the Trail
Authors: Acha Smart , Fadairo James , Ogiesoba Dennis , Okeke Ikenna , Emmanuel Tata , Brown Joseph A. 
Published: July 2019

Abstract
The Nigerian Petroleum Development Company Limited (NPDC), and First Hydrocarbon Nigeria (FHN) its joint venture partner in Oil Mining Lease (OML) 26, established OML 26 Asset Management Team (AMT) to manage the lease together with all the assets and facilities on behalf of the joint venture (JV). The facilities include the flow station, the compressor station, and the gantry at Ogini field, a LACT Unit at Eriemu, and Operational Base for alternative evacuation in Asaba – Ase all in Delta State, Nigeria.
Since the inception of the AMT in 2016, the asset has achieved and maintained a GOAL ZERO HSE performance record. Achieving GOAL ZERO HSE performance in a brown field like OML 26 is a herculean task. It is so, considering the operational challenges that require aggressive interventions in the forms of various projects, and the increased field activities. The debottlenecking activities results in more manhours, greater exposures and a high propensity for environmental impact. In line with the vision of the AMT to be the Best Performing Energy Investment (BPEI) the HSE department established a proactive system for identifying and managing operational risks and ensuring regulatory compliance consistently.
This paper highlights the tremendous efforts, strategies and policies of the HSE department in ensuring success and meeting set HSE goals. It focuses on the costs in terms of commitments, governance and drive at all levels in achieving a sustained impressive performance and compliance to regulatory and international standards.
Pressure Relief Management Philosophy for MPD Operations on Surface Stack HPHT Exploration Wells
Authors: Benyeogor Ogochukwu , Jambol Donald , Amah Obinna , Obiga David , Awe Sunday , Erinle Adeyemi 
Published: July 2019

Abstract
Managed pressure drilling (MPD) is an adaptive drilling technique used to improve the economics and to mitigate risks associated with drilling high pressure and high temperature (HPHT) exploration wells where the drilling window is often narrow. The technique involves the combination of surface back pressure and fluid hydrostatic column to provide the required bottom hole pressure for safe drilling. Typical MPD equipment spread includes rotating control device (RCD), chokes, high pressure lines and gate valves with Pressure relief valves (PRVs) incorporated. The primary purpose of the PRV is to protect the MPD surface equipment and the formation from being overpressured. The relief valve achieves this by bypassing the normal fluid flow path for MPD operations and relieving the system pressure to the rig Mud gas separator (MGS) through a dedicated line. Each time a PRV is activated the resulting loss of surface back pressure increases the risk of taking a kick. On the other hand, when a PRV is not activated, an excessive increase in surface pressure raises the risk of formation fracture leading to losses. Therefore, the performance of the PRV has an immense impact on assessing the risk of a well control situation, which may be caused by either loses due to formation breakdown and consequently a kick from loss of the hydrostatic pressure component of the equivalent surface density (ESD) or an influx as a result of loss of surface back pressure component of the ESD due to loss of integrity of surface equipment).
Pressure Relief Management philosophy generally covers decisions such as which parts of the well system (surface and subsurface) are to be preferentially protected by the PRVs, selection of activation pressure for high level alarms, types, number and setpoints of PRVs in the MPD system during different phases of the drilling operations - drilling, connections and tripping, and MPD choke full-opening pressure. These values are dependent on formation integrity test (FIT), mud weight, drilling window, annular friction pressure and operating envelope of RCD. The set points require adjustment depending on the hole size and flow rate and may be different during completion and well control operations.
This paper describes the Pressure Relief Management philosophy for a HPHT well drilled in the Niger delta. It looks at factors that drive the high-pressure alarm setting values, choice of PRV types, placement and the part of the well system being protected, PRV tripping and reset values, and MPD choke full opening pressures. It also describes the challenges and risk assessment that influenced the selection of set points (single or dual setpoints) for different phases of the drilling operations.
Evaluating the Performance of Local Anionic Emulsifier as a Possible Emulsifier for Synthetic-Based Mud System for Drilling Operations
Authors: Amorin Richard , Broni-Bediako Eric , Adanvor Joel Bright , Appau Prince Opoku 
Published: July 2019

Abstract
In the process of formulating oil-based muds, emulsifiers or surfactants are added to help build a strong oil-water emulsion. Currently, all the emulsifiers used in mud formulation in Ghana are imported increasing drilling cost. This also do not promote the local content and local participation policy of the country in the oil and gas sector. There are equally potential local emulsifiers that could be used in these mud formulations to reduce cost. This research, therefore, evaluated the performance of local anionic surfactant as a possible emulsifier for an ester-based oil mud system for drilling operations. A Synthetic-Based Mud (SBM) was formulated with varying concentrations of both local (L) and commercial (C) emulsifiers from 0% to 100% at a step of 25% after which their rheological properties evaluated. The rheological properties were evaluated for unaged samples at temperatures of 80 °F, 120 °F, 180 °F and aged samples at a temperature at 180 °F. The performances of the mud samples were tested using Gel Strength at 10 seconds and 10 minutes, Plastic Viscosity, Yield Point and pH at each varied concentration of emulsifier following closely the American Petroleum Institute (API) standard test procedures. The overall performances of the mud samples in order of descending were; BL100% &gt; AC100% &gt; EC25%L75% &gt; CC50%L50% &gt; DC75%L25%. It was observed that the local emulsifier performed equally well and even better than the commercial emulsifiers at the test conditions presenting the local emulsifier as a potential emulsifier for the formulation of SBMs for the oil and gas industry.
Evaluation of Rock Failure Models for The Determination of a Safe Mud Weight Window During Drilling Operations in The Niger Delta
Authors: Success Chioma Ogbechie 
Published: July 2019

Abstract
Unstable boreholes due to tensile & shear failure results in serious drilling problems. This increases the non-productive time spent in the field and the cost of reviving failed wells in the oil and gas industry in order to mitigate or prevent borehole failure, different rock strength criteria models have been developed to predict the optimum required mud weight but unfortunately, not all models fit for all formation considering the different drilling conditions, hence these models need to be evaluated to check their validity and accuracy for drilling stable wells in the Niger Delta. To achieve this purpose, collapse and fracture pressure that defines the lower and upper boundary of a mud weight window are calculated using derived formula equations from three failure criteria models; Hoek-Brown failure criterion, Mohr-Coulomb failure criterion and Mogi-Coulomb criterion failure criterion. This is achieved using Microsoft Excel and the simulation is done on a plot to show the different mud window by each model for comparison. The input parameters relevant for this study are pore pressure, in-situ stress data and rock mechanical properties which were acquired from a high-pressured zone in an xxx-onshore oilfield of the Niger Delta. A plot of the predicted optimum mud weight vs the actual mud weight against depth is compared to check the accuracy of each model to conclude on the failure criterion that is best fit for the formation in this field. The results showed that Hoek-Brown failure criterion gave an unrealistic outcome, when used to drill will lead to borehole breakout. Mohr-Coulomb and 3D Mogi-Coulomb criteria gave similar results which can be used but Mogi-Coulomb is recommended for drilling stabilized vertical wells due to the consideration of intermediate principal stress effect on rock strength over the conservative Mohr-Coulomb.
Demonstrating the Value of Early Incorporation of Dynamic Data during Probabilistic Assessment for a Niger Delta Gas Condensate Reservoir
Authors: Ogbuagu Frank , Silpngarmlers Lynn 
Published: July 2019

Abstract
The paper aims to highlight the importance of using adequate dynamic data to ground-truth reservoir simulation models early in the production life of a field. This study also highlights the benefits of adequate instrumentation and data capture, as well as the need to review assumptions made for green fields in their first few production years.
This study reviews two vintages of probabilistic assessment for an offshore gas condensate reservoir. An earlier probabilistic assessment for the case study reservoir was built based primarily on core data from two analogous reservoirs, one of which was from the same field, prior to the availability of bottom hole pressure and drawdown data. Initial history match and forecasts showed a significantly poor production performance with significant impact on the condensate reserves volumes from the single well in the reservoir.
Following the acquisition of pressure data from the downhole gauges and pressure transient analyses results, the model recalibrated in line with estimated distance to boundaries, drawdown and productivity indices. Incorporating the additional data from the downhole instrumentation during the history match showed the earth model severely underestimated the permeability of the reservoir. Matching the drawdown and well test data required a significant permeability multiplier for the low and mid case models for the reservoir.
A comparison of results from both model vintages showed significant differences in the expected production plateau for the reservoir and consequently reserves estimates. These finding demonstrates value of the acquisition of multiple downhole dynamic data and the pitfalls with reservoir performance forecasts and reserves assessments when simulation models are not adequately constrained with dynamic well data early in the production life of the reservoir.
Cement Packer Installation in Highly Deviated Well Using the Balanced Hydrostatic Plug Concept through Coiled Tubing: Offshore Niger Delta
Authors: Onuh Haruna , Abdulsalaam Ilyas , Abdurahaman Fatima , Osarowaji Emmanuel , Chemmarikattil Rohan , Ibrahim Charles , Ntiwunka Greg 
Published: July 2019

Abstract
The "balanced cement plug" concept has long been a standard industry practice for setting plugs in a wellbore. This requires setting a hydrostatic plug consisting of a column of brine, spacers, and cement slurry pumped into the annulus of a tubing/drillstring to create a balanced U-Tube that equates the hydrostatic head in the drillstring/tubing and annulus. Fluid volumes are calculated accounting for fluids both inside and outside the pipe at the given gradient, thus resulting in a hydrostatically "balanced system."
Recently, this technology has been successfully deployed for cement packer design and execution using coiled tubing (CT) at a depth of 1,899 ft above the production packer with 111 bbl of calcium chloride brine existing (cement accelerator) below the tubing punch interval in the tubing-casing annulus. The cement packer installation design was for accessing bypassed hydrocarbon in high-angle (65 to 72º) deviated wells offshore the Niger Delta. Design considerations are reviewed and precautions for placement of high angle cement packer through CT are discussed.
Initial designs to isolate the lower depleted zone were futile because of failed zonal isolation with mechanical plugs. Thus, an attempt to isolate the lower interval by pumping cement with 15% excess (openhole volume) led to having 17 bbl (1,899 ft) of cement within the 3.5-in. production tubing, and above the production packer. The CT deployed cement packer installation without a cement retainer presents unconventional solutions for placing cement at the height of 1,899 ft. The operation was successfully executed and the temperature log confirmed top of cement as proposed during the design phase. The holdup depth in the tubing was also tagged as expected with no cement U-tubing from the annulus. Post-job shut-in tubing and casing pressures, quantity of cement pumped, and flow testing have proven the success of the design and procedure implemented in challenging wellbores.
The Loss of Primary barrier: An Integrated Approach of Downhole Leak Location and Quantification. Case Study
Authors: Volkov Maxim , Yurchenko Andrey , Ellis Remke 
Published: July 2019

Abstract
Failure of the primary barrier in most cases results in observable sustained annulus pressure. For other such cases, sustained annulus pressure may not result, and leak associated fluid movement remains confined to deeper intervals, for example as cross flows.
This manuscript introduces a comprehensive approach to assess the current status of primary and secondary barriers and, for this case of integrity loss, to quantify the downhole leaks rates. The assessment includes: Determining individual pipe wall thickness of first two concentric metal barriers using electromagnetic pulse logging techniqueSpectral Noise Logging to locate the active leaks and to verify the sealing integrity of cement barriersHigh Precision Temperature logging for downhole leak rate quantification utilizing temperature modeling
The paper contains the physics of measurement, lab and field tests of the barrier assessment technologies, followed with a case study: A single string gas producer, with sustained A-annulus pressure. Additional survey findings allowed the identification and quantification of a crossflow resulting from leaks.
Defining the Optimal Development Strategy to Maximize Recovery and Production Rate from an Integrated Offshore Water-Flood Project
Authors: Abdulfatah Hajara Kabeer , Stanley Okafor Ikechukwu , Nzerem Petrus , Jakada Khaleel 
Published: July 2019

Abstract
A reservoir development plan provides the necessary guidance and information for establishing whether or not a project is economically viable considering possible development project options, risks and uncertainties in order to define the most optimal development concept that will increase oil production and reduce production costs. The aim of this project was to determine the optimum way to develop and produce an offshore oil field in a manner that considers risks and uncertainties and values stakeholders’ interest. A stochastic multi-tank reservoir model was created using MBAL and it consist of various producers and water injection wells. Sensitivity analysis was carried out on Seven development scenarios with a view to examine effect of maintaining reservoir pressure, sustaining well productivity and injectivity, optimize well counts and improving well delivery- timing, cost and well performance. The economic viability of each of the development scenarios was carried out to determine the net present value, incremental project cash flow, unit technical cost, unit development cost and breakeven price BEP of each of the scenarios. The optimal development strategy was then selected based on the production performance and key economic indicators. The project provided an opportunity to develop an additional 396MMbbls of recoverable oil from 32 new wells both producers and injector wells (P+WI).
The Impact of Reservoir Heterogeneity in the Modelling of Scale Inhibitor Squeeze Treatments
Authors: Uzoigwe Friday , Mackay Eric J. , Vazquez Oscar 
Published: July 2019

Abstract
The oil and gas industry require technologies to prevent mineral scale formation and deposition in reservoirs and production systems. One commonly used method to achieve this is the scale inhibitor squeeze treatment. The challenge addressed here using modelling is to prolong the squeeze treatment lifetime in heterogeneous reservoirs, thus, reduce the cost per barrel of oil produced, especially in deep offshore and remote locations.
Key to squeeze life extension is ensuring optimum scale inhibitor retention on rock matrix. Therefore, the inhibitor must contact the reservoir rocks and be distributed amongst the layers in proportion to the expected water production rates per layer, which will be determined by reservoir heterogeneity, system geometry and gravitational effects. These effects are studied for an offshore water flooded reservoir by means of a reservoir simulation model.
The study reveals that reservoir heterogeneity generally improves inhibitor squeeze treatment performance as measured at surface for the entire well, with more inhibitor being placed in the zones with high permeability-thickness product (kh). However, downhole pressure differentials can result in higher pressure layers being unprotected for longer periods before the inhibitor concentrations for the entire well goes below the Minimum Inhibitor Concentration (MIC).
The use of diversion techniques is shown by simulation work to improve placement and thus help achieve a successful inhibitor squeeze treatment in all the reservoir layers. However, inhibitor concentrations may remain relatively high in layers that do not produce much water, resulting in some wastage of inhibitor as a penalty for delaying the time before re-squeezing is required.
The modelling helps understand where scale could occur and the best management strategy for scale prevention or control; identifying the impact of scale; giving insight into the best inhibitor squeeze treatment options and expected performance; and providing input needed for the economic model required for good reservoir scale management.
Application of Geographically Weighted Regression to Model the Effect of Completion Parameters on Oil Production – Case Study on Unconventional Wells
Authors: Wigwe M. E , Watson M. C , Giussani A. , Nasir E. , Dambani S. 
Published: July 2019

Abstract
Spatial data exists practically everywhere, including the oil and gas industry. Several factors drive the distribution of the location of oil and gas wells: performance of existing wells, available acreage, need for operators to maintain a certain amount of production and to stay competitive. Some of the important parameters to consider in the design of a completion job for an unconventional oil and gas well are the length of lateral (and by extension perforated interval), number of stages, total pounds of proppants, total volume of fluid pumped, injection pressure and injection rate.
In big data analytics and building of a regression model to capture the effects of these parameters on oil production, the practice has been to analyze wells in similar formations or similar basins, even when these wells are miles apart. Due to the presence of spatial autocorrelation and non-stationarity in such data, the recommended practice should be to take these spatial dependencies into account by using geographically weighted regression (GWR).
In this paper, we present an application of GWR in location-based regression modeling to capture the effect of these completion parameters on the first six months of oil production in 5700 wells in the Bakken and Three Forks formation in North Dakota. GWR builds different models for every location, leading to a spatial distribution of variable coefficients. This model is well suited to capture both local and global variations in our dependent variable. We also compare the results obtained with that of three other models: multiple regression model, artificial neural network model and universal kriging. Just like the use of kriging, GWR model resulted in a much-improved prediction of oil production as captured by the goodness-of-fit diagnostics (R squared, AIC, and RMSPE), compared to the other two non-location-based models. We recommend the use of the GWR model in the prediction of oil or gas production when spatial non-stationarity exists.
The Application of Holistic Workflows for Sour Reservoir Management on the X Field
Authors: Kuku O. , Ekeigwe A. , Ajakaiye G. , Olushina T. , Harper C. S. , Zheng Y. , Green S. A. 
Published: July 2019

Abstract
The X field has been in production since 2011 and some of the reservoirs are on a water flooding-scheme for pressure support. The water flood commenced solely with the injection of seawater and more recently commingled produced water and seawater. A few years into the production, it was observed that production from at least one of the reservoirs has become sour.
Thus, a reservoir souring study of the X field was conducted to ascertain the immediate cause of souring, determine future sulphide production trend and provide recommendations on sulphide concentration and integrity monitoring, bacteria monitoring practices and mitigation against the current souring events on the X field.
The study was conducted by a joint team from Oriental Energy Resources Limited (OERL) - operator, Baker Hughes, a GE company (BHGE) in collaboration with the regulatory agency, the Department of Petroleum Resources (DPR).
The study utilized BHGE proprietary workflows, including those previously documented in SPE-179921-MS, and drew on significant routine operational data, and specialized data such as sulphide and sulphate isotopes, detailed water compositions (including Volatile Fatty Acids -VFA), serial dilution and molecular microbiological enumeration techniques and microbiological sequencing techniques.
The study concluded that the primary source of souring was microbiological and that this souring event was not limited to the focus, high H2S reservoir (XY) but was observed to be present on all water injected reservoirs in the X field. It was felt, though not proven, that the Sulphate Reducing Bacteria (SRB) may have been derived from the seawater. The microbiological Deoxyribonucleic Acid (DNA) analyses indicated that the primary carbon source, once VFA had been sufficiently depleted, was likely to be the biodegradation products of hydrocarbon degrading bacteria within the reservoir.
The study also concluded that, due to the lack of carbon source constraint for the bacteria, the required inhibitory nitrate dose rates would be uneconomically high and would yield no benefit over the effects of replacing Sea Water Injection (SWI) with Produced Water Re-Injection (PWRI). However, it has been observed that sulphate concentration in production had declined since the cessation of seawater injection.
The reservoir souring study has resulted in a heightened level of surveillance, thereby leading to a safer operating environment on the X asset. The field operating strategy and chemical application has been modified to allow the overall magnitude of sulphide related hazards and cost of operating the field to be reduced.
This project is a first in the Nigerian oil production operations, involving an open collaboration between an operator, a government body and a service vendor on reservoir souring.