bluuebunny/crossref_metadata_2025_split huggingface dataset:
Silica Based Surfactants for Enhanced Oil Recovery
Authors: Adeniyi Adekunle Tirimisiyu , Olafuyi Olalekan A. 
Published: October 2018

Abstract
A new silicate based surfactant, comparatively proven to be cheap and efficient, for enhanced oil recovery is developed. The silica based surfactant was prepared from silicate with highest percentage of silica and evaluated for reduced interfacial tension, and core flooding experiments simultaneously with sampled commercial surfactants, for its potency to aid oil flow. The feedstock, for silica based surfactants, composed massively abundant eartly silicate, rich in silicon. The silica is hydrolyzed at elevated temperature and continously heated up to form oxides of silica. The performance of the silica based surfactants was studied for its oil recovery efficiency with a commercial surfactants as a guide. The results showed that silica based surfactants dissolves in produced water, an adjusted interfacial tension value of 0.101dyne/cm was obtained. An improvement of additional 10% of oil initially in place was produced ahead of a branded commercial surfactants, from a set up that has undergone excessive water flood. The results obtained, confirmed that there is a possibility of developing new surfactants from sustainable abundance of earthly silicate.
Managing Shallow Casing Leaks in Well Completions; Case Study of a Single Zonal Well in Niger Delta
Authors: Oghale Longfellow , Noruwa Osahon , Osadebea John , Jordan Fisayo , Simon Osa , Emmanuel Ejimofor 
Published: October 2018

Abstract
Re-entering old and mature wells is necessary to chase initially classified marginal hydrocarbon volumes. Many wells drilled in the 60s and 70s but suspended have become attractive to small players with relatively low overheads and tax regime. As a marginal field operator, such opportunities are classified as short term development opportunities establishing quick cash flow to further field development.
Casing failure in an old well drilled through shallow faults can pose serious challenges to re-entry and workover operations. This paper presents the solution to a challenging casing leak interval across a shallow fault zone which could not be squeezed off with conventional cement squeeze technique.
The failure of routine casing test prior to drill stem test during a re-entering and completion of a well drilled and suspended for 36 years necessitated the consideration of several isolation methods. Attempts made to squeeze off the leak interval across the fault zone using cement proved abortive due to the size and nature of the fault. Casing patch was considered but not available in-country as at the time of the operation. This led to a novel approach of isolating the leak interval with the completion packers and subsequently perforating the well through-tubing. The leak was successfully isolated and the well completed. The well has produced over 0.5 million barrels of oil and 4.5 billion standard cubic feet of gas and still contributing over 10% of daily field production. This method was also used in a dual completion in Niger Delta to manage two different pressure gradients.
Multi-Rate Testing via Gas Plant with Clamp-On meters: A Niger Delta Case Study
Authors: Mogbolu Emmanuel , Udobata Uchenna , Amaefuna Magnus , Okereke Onyedikachi , Oghene Nkonyeasua 
Published: October 2018

Abstract
The primary focus of a Well, Reservoir and Facility Management (WRFM) team is to guarantee shareholders’ return on investment by improving production and optimizing recovery. Several best practices abound in the industry to achieve this goal. Multi Rate Testing (MRT) is a statutory requirement on gas wells; one of the most important functions of MRT is to obtain the wells’ deliverability for optimal reservoir management. Obeahon et al (2015) had presented an alternative approach to Multi-Rate Testing using existing gas central processing facility. This approach is applicable provided all the metering equipment are installed. This paper presents an alternative MRT approach for gas plants which do not have all the metering equipment installed. This was applied in the OMAUO Field and can be applied on other fields with similar situation. OMAUO NAG (ONAG) operations had been plagued with the following problems: the absence of wet gas meters to measure the well potentials, uncertainty with CGR/WGR of the wells for model calibration/ well's optimization, challenge of conducting conventional MRT via third party due to cumbersome logistics/cost (ca. US$ 2 mln/well) and no test facility. Thus, potentials and deliverability can only be assessed via third party MRT operations and absence of wet gas meters had limited the ability to use the Gas Plant to carry out MRT. The proposed approach was executed by utilizing clamp-on meters (to measure wet gas) at the manifold and the Gas Plant as a giant test separator for the individual well testing. Pilot tests were successfully carried out on three wells that were tested individually (OMAU015T, 016T and 017T). The technical integrity of the acquired data was in line with that obtained from MRT via a test separator and the results of the analyzed data were found to be representative. The low CGR and WGR values obtained from the analysis also aligned with that obtained from the previous MRT (via third party mobile test separator). The pilot tests saved US$8mln for four wells tested with minimal HSSE exposure, gained additional volumes of gas (ca. 50 MMscf/d) due to the optimization exercise, reduced deferment by reducing execution time and aligns with the competitive drive within the oil and gas industry. The outcome of carrying out this pilot test via the use of clamp-on meters can be leveraged upon by other gas plants without requisite meters and test facilities.
Improved Water Soluble Polymers for Chemical Flooding
Authors: Eiroboyi I. , Ikiensikimama S. S 
Published: October 2018

Abstract
Nanotechnology has shown enormous progress in the petroleum industry especially in the area of Enhanced Oil Recovery. However, field experience has shown that the major challenge facing polymer flooding is polymer degradation under reservoir conditions such as high temperature and high salinity. Though Partially hydrolysed polyacrylamide (HPAM) is the current widely used polymer, it is also very sensitive to salinity, shear, thermal degradation due hydrolysis of polyacrylamide introduced as a result of negative charges on the backbones of polymer chains which in turn causes an alteration on the rheological properties of the polymer solution.
The rheological behaviour for different solutions of Guar gum and Gum Arabic containing different salt was evaluated to study the effect of nanoclay and other additives on the stability of these biopolymers. The viscosity of these polymer solutions was measured using a rheometer and in each measurement, the shear rate was changed, and the effect of this change on the viscosity was measured. Results showed improved stability at different range of salinity and level of concentration of the polymers.
Reducing TVD Uncertainties Using Dual Inclination and SAG Model
Authors: Ulaeto Ubong , Nwobi Zimuzo , Ibrahim Hamza , Ubadigha Emmanuel , Asiodu Ndidi 
Published: October 2018

Abstract
Uncertainties in True Vertical Depth (TVD), over the years in the practice of drilling, have been a concern for precise wellbore position and collision avoidance. Accurate well placement in thin oil bearing zones have necessitated service companies to design Bottom Hole Assemblies (BHA) capable of providing actual hole inclination with high precision.
TVD accuracy is normally a function of Measured Depth error and Inclination error. These errors could arise from sensor calibration, misalignment error and BHA Sag. In highly deviated wells, inclination is the dominant contributor to TVD uncertainty. Reduced inclination uncertainty therefore results in reduced TVD uncertainty. By measuring the inclination of the well at same depth with different sensors positioned in different locations in the BHA in rotary or non-rotary mode, the improved accuracy in TVD is achievable. This technique, also known as Dual Inclination, is a survey method used to increase inclination accuracy, and thereby reduce TVD uncertainty.
This paper discusses practical field cases for two long tangent and horizontal wells drilled at different locations of West Africa where Sag corrections and dual inclination were utilized to reduce the error in TVD prediction. The technique was adopted to avoid collision with existing and future wells and produce the oil rim in the zone of interest. Final results showed difference of 2ft and 3ft in TVD for both wells with 6ft and 4ft difference in vertical uncertainties respectively. The data utilized for this study were obtained from the well survey from the two sensors within the BHA. Also discussed are the Quality Control criteria to be met for right application of this technique. Recommendations for highly deviated wells and fields with greater well density are also discussed.
Optimizing Completions Cost by Using the Low Gravity Ball for Production Packer Setting Operations
Authors: Salami Hassannah , Ifediora Emmanuel , Numbere Otokini , Rahman Muhammed Abdul 
Published: October 2018

Abstract
The completion cost of development wells is usually 30-50% of the Authority for Expenditure (AFE). This depends on the number of zones to be completed, the completions strategy, cost of downhole jewelries and complexity. The quest to develop these complex un-stacked reservoirs has increased the tortuosity of the well plan and the complexity of the wells. This has in turn increased the completion complexity and has significantly increased the time taken to deploy the completion accessories, and the time taken to set the packer.
The sand management strategy and lower completion philosophy for the case study field, is setting Stand Alone Screens (SAS) as the lower completion assembly. Over the years, Addax Petroleum has used the metallic ball to set the lower completion production packer in a slightly straight well. Due to the need to optimize the well architecture and the tortuous profile of the well, the average production packer is now set at circa 80-85 degree's inclination. This optimization plan, significantly increased the amount of time required to circulate the metallic ball to the lower completion ball seat (a device engineered to aid the setting and hanging of the lower completion assembly in the production casing). This increase in time has further increased the completion costs.
To ensure that the development cost is reduced due to the current unstable and low oil price, a plastic setting ball (with lower specific gravity) was identified, risk assessed and used successfully to significantly eliminate the excess time for completion operations.
This paper reviews the challenges experienced using the metallic packer setting balls in highly tortuous horizontal wells. It also shows and discusses the huge cost savings achieved in case study wells where the low gravity packer setting ball was used to set the lower completions production packer.
Evaluation of a Depleted Oil Reservoir for Gascap Blowdown Using 3D Simulation Models: A Case Study of Chrome Field Development
Authors: Nwonodi Chike , Onwuchekwa Chukwuma , Ekong Inem , Amrasa Kefe , Osadjere Peter 
Published: October 2018

Abstract
Gas Cap Blowdown (GCBD) involves a process of depressurizing the gas cap of an oil reservoir to produce the associated gascap volumes, more often after the oil rim has been depleted of significant oil production. Thus, the optimal development plan for such reservoirs carries both large technical and commercial uncertainties and a robust technical evaluation is required to underpin commercial decision. In most moderate to strong aquifer drive reservoirs, the displacement of gas as the oil rim moves upwards into the gas cap causes residual oil losses with trapped gas.
This paper details the integrated study of a gascap development of oilrim reservoir initially developed by twelve (12) oil wells and with over 40 years of production history; and overlained with an undeveloped huge gascap with M-factor, m&gt;1.6. The reservoirs comprise of number of communicating blocks by a series of nonsealing synthetic faults and a number of nonsealing transverse faults of up to 200 ft throw. Full scale 3-D simulation models; using the Shell's proprietary 3D dynamic modelling application; Modular Reservoir Simulator (MoReS) were deployed to assess subsurface uncertainties and history match reservoir performance of the reservoirs. The impact of resaturation of original gas cap volume and timing of gascap blowdown on the ultimate recovery of the gascap were exhaustively evaluated. Optimal development of the gascap was assessed against a range of technical uncertainties which then formed the basis for development of other reservoirs in the field that were not subject to the full uncertainty assessment.
From the results of the subsurface uncertainty analysis and extensive history match, three (3) gas wells targeting the gascap were proposed to develop the reservoir and optimum timing of gas cap development was evaluated, while concurrently producing the remaining oil volumes with exising wells. In addition, the results from sensitivity analysis evaluated different timing for commencement of gascap blow down and the associated incremental recoveries. Also, for residual oil in the presence of gas, reduced range of values upto 30% of the oil-to-water residual saturation results due to the different blow down timings.
Real Time Reservoir Management Successes at Sonam Gas Condensate Field, Offshore Nigeria
Authors: Eruvbetine Obor , Ogele Chile , Aitokhuehi Inegbenose , Charles Dawari , Onojeghuo Charles 
Published: October 2018

Abstract
Real Time Reservoir Management (RTRM) has as its foundation pillars real-time data acquisition, monitoring and surveillance. A fit-for-purpose real-time data acquisition, monitoring and surveillance program implemented at the Sonam Gas Condensate Field has led to considerable RTRM successes, resulting in a value capture of over $6.0 MM in a six-month period.
This paper discusses how RTRM was implemented in the Sonam gas condensate field, offshore Nigeria and how the availability of this data resulted in significant value capture. Setup was achieved with negligible incremental cost (~$0.003 MM) as existing control systems and Information Technology (IT) infrastructure provided the backbone for the system. Data from permanent downhole gauges (PDHGs) in the wells were linked to the platform Integrated Control System along with flowrates, pressures and temperatures from across the production platform. The data is then streamed to office locations via the existing network infrastructure for quality checks, interpretation and decision making.
The RTRM solution enabled the optimization of the completion program for the next set of development wells for the field. This was achieved using Pressure Transient Analysis on an existing well during several opportunistic shut-ins. This data would have been difficult and expensive to acquire given the commissioning and drilling activities that were ongoing. However, due to the real-time streaming and analysis, every production shut-in yielded value. The visibility of the data enabled, amongst others, real time decision making and intervention to ramp-up production, attainment of well target rates, calibration of flow rate meters and optimization of test separator operating parameters.
This paper demonstrates the tremendous value that could be created by implementing RTRM. The authors are convinced that the value demonstrated by Sonam RTRM reinforces the need for decision makers to ask, "why are we not implementing a fit-for-purpose RTRM in every producing asset"?
Simultaneous Flow Assurance and Production Optimization Using Chemical Paraffin Inhibition Method
Authors: Nwankwo Kenechukwu Obiajulu , Chikwekwem Chijioke James , Nwankwo Princess Christiana 
Published: October 2018

Abstract
This paper highlights efforts to eliminate wax production, by deriving a permanent flow assurance solution for a producing well and mitigate frequent downtime and expensive remediation operation.
In two case studies, the efficacy of a Paraffin dispersant was compared with that of a Paraffin inhibitor, with respect to a producing well's wax formation tendencies and characteristics with the view of optimizing well performance subject to chemical injectivity.
In the first case, well fluid was continuously treated with Paraffin dispersant to prevent wax deposition and subsequent blockage on the flowline but this effort proved ineffective because of periodic remediation. There was no significant performance improvement in this case.
In the Paraffin inhibitor case, an appreciable increase in pressure differential across choke was observed as well as significant production increase which improved with the treatment time of the well fluid with the paraffin inhibitor.
It was evident that Paraffin Inhibitor Injection was not just a flow assurance solution but also a production optimization tool. The project also saved the company about a million dollars annually, used for remediation of wax blockage on the flowline and sometimes sectional replacement of the flow line. Hence operation was a cost-effective method to achieve flow assurance and optimal production performance.
Advances in WRFM Technology Integration
Authors: Egbe ThankGod , Sanni Gideon , Chiroma Abba 
Published: October 2018

Abstract
Existing technologies currently utilised in well, reservoir & facility management (WRFM) to gain detailed insights into the issues affecting the petroleum production system are discipline specific, hence focus is mainly given to analysis of each component of the production system separately. These isolated functional analyses are sometimes based on inconsistent datasets which may lead to erroneous diagnosis of production problems and could ultimately result in failed well interventions if not rigorously checked via multi-disciplinary reviews.
The multi-disciplinary nature of WRFM practice requires that the discipline-specific interpretations of the well, reservoir & facility models be integrated to eliminate potential inconsistencies and improve quality of interpretations. This paper presents a new technology for WRFM workflow integration based on the principle of integration of interpretations. The benefits of integration of interpretations in WRFM data democratisation and process digitalisation are also highlighted.
A Nonempirical Relative Permeability Model for Hydrate-Bearing Sediments
Authors: Singh Harpreet , Myshakin Evgeniy M. , Seol Yongkoo 
Published: October 2018

Summary
There are currently two types of relative permeability models that are used to model gas production from hydrate-bearing sediments: fully empirical parameter-fitting models [such as the University of Tokyo model (Masuda et al. 1997) and the Brooks and Corey model (Brooks and Corey 1964)] and partially empirical models [such as the Kozeny and Carman model (Wyllie and Gardner 1958) and capillary-tube-based models that assume only a single phase]. This study proposes an analytical model to estimate relative permeability of gas and water in a hydrate-bearing porous medium without curve fitting or use of any empirical parameters. The model is derived by conserving the momentum balance with the steady-state form of the Navier-Stokes equation for gas/water flow in a hydrate-bearing porous medium. The model is validated against a number of laboratory studies and is shown to perform better than most empirical models over a full range of experimental data. The proposed model is an analytical function of rock properties (average pore size and shape, porosity, irreducible water saturation, and saturation of hydrate), fluid properties (gas/water saturations and viscosities), and the hydrate-growth pattern [pore filling (PF), wall coating (WC), and a combination of PF and WC]. The benefits of the proposed model include sensitivity analysis of relevant physical parameters on relative permeability and estimation of rock parameters (such as porosity, pore size, and residual water saturation) using inverse modeling. The model can also be used to estimate two-phase permeability in a permeable medium without hydrates.
The proposed model was used to analyze the effects of pore shapes, the hydrate-growth pattern, variable gas saturation, and wettability on relative permeability. The sensitivity results produced by the proposed model were verified using observations from other studies that investigated similar problems using either experiments or computationally expensive pore-scale simulations.
Explaining Sustained “A”-Annulus Pressure in Major North Sea High-Pressure/High-Temperature Fields
Authors: Mainguy M.. , Innes R.. 
Published: October 2018

Summary
Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their “A” annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the “A” annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained “A”-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the “A” annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
Modeling Foam Breakup in Batch Separators and Cylindrical Cyclones
Authors: Moncayo J. A. , Dabirian R.. , Mohan R.. , Shoham O.. , Kouba G.. 
Published: October 2018

Summary
Models are developed for foam breakup in a batch separator, as well as inlet–cyclone and gas/liquid–cylindrical–cyclone (GLCC) compact separators, by improving the Saint–Jalmes et al. (2000) “1–g” foam–batch–separator model. The modified batch–separator model shows a better performance with respect to experimental data than does the original model. An extension of the modified “1–g” foam–batch–separator model to swirling foam flow in cyclones is developed, which accounts for the effect of higher g–forces in the cyclones. The extended model accurately predicts experimental foam–breakup data for both the inlet–cyclone and the GLCC compact separators.