bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Deterministic Mohr Shear Failure Criteria in Analyzing Top-Seal Integrity – Zern Field Example
Authors: Iyowu Olakunle , Ozoemene Uchechukwu , Azubike Obi 
Published: October 2018

Abstract
Nigeria's gas policy vision to be an attractive gas-based industrial nation implies that we need to continuously harness the abundant gas resources in the subsurface. This may imply that many more gas projects will be required to meet the country's aspirations.
Pressure depletion under natural depletion in gas development are usually much more than in oil development. There may also be compression as part of maximising gas depletion which would lead to even further pressure depletion at end of life compared to oil development. It is therefore imperative to assess the impact of pressure depletion on Top Seal Integrity.
Top Seal failure can lead to loss of reservoir-fluid containment with resultant uncontrolled flow of fluids (liquids or gases) from the reservoir into the seal or into the deep overburden, and then upwards due to reservoir pore pressure or buoyancy effects which may manifest as internal blowout.
ZERN field is a partially appraised field that has been identified for gas development. We have a fair understanding of our reservoir response to depletion having been producing oil reservoirs for over 50years; however, gas production is somewhat new and there are no mature analogues for benchmarking in SPDC. Mohr coulomb shear failure criteria was used to assess the risk of top seal failure. A set of deterministic scenarios were built integrating information from planned start of field production to predicted end of life and incorporating realisations of rock strength parameters from ZERN field and analogue field.
Three pre-production scenarios were coupled with nine post-production scenarios for each depleting reservoir. The resulting Mohr circle envelopes for the different scenarios were analysed per reservoir to arrive at best engineering judgement for de-risking top seal integrity for the ZERN field.
Impact of Flood Rate, Salinity, and Wettabiliy on Waterflood Oil Recovery Using Lab-On-A-Chip Method
Authors: Okoro Franklin 
Published: October 2018

Abstract
Wettability, pore geometry, oil viscosity, and water salinity are among the factors with dominating effects on microscopic waterflood efficiency, and consequently on the ultimate oil recovery. Optimal oil recovery requires a great understanding of the nature and manipulation of these factors. Most early and more recent studies on the effects of these factors on waterflood oil recovery have not reached a consensus yet. To gain a better understanding of the effects of these factors on the microscopic performance of a waterflood process, experimental studies were conducted using Lab-on-a-chip method. The selected conditions for displacement efficiency comparisons include: mixed-wet and water-wet conditions, high and low viscous oils, three different waterflood rates ((0.05 μL/s, 0.1 μL/s, and 0.15 μL/s), and two different flood water types (sea water and distilled water). Two grain minerals were used in the experiments (calcite and quartz grains). Image processing technique was applied to analyse and compare the displacement efficiency in each experiment using an automated code developed with MATLAB. Experimental results showed that mixed-wet media, faster flood rate, low salinity flood water, and low viscous oil are favourable to waterflood oil recovery. This laboratory study also illustrates that a microfluidic chip can be successfully used for Enhance Oil Recovery (EOR) studies.
The Use Of Clamp-On Gas Flowmeter In Gas Lift Operations- Badan Field Experience
Authors: Obong Benjamin , Franklyn Ogoleh , Tima Ekine , Azibapu Franklin 
Published: October 2018

Abstract
Over the years, especially in brown field operations, injected lift gas metering has remained a concern among operators. In some legacy fields, there is little or no functional gas injection metering in place. A whole lot of challenges ranging from obsolete field metering equipments, OPEX, meter calibration and maintenance challenges, etc, has impacted optimization opportunities from gas lifted wells. At other times, it has been difficult to justify facilities expenditures for late-life, gas lifted wells. Operators must therefore balance the benefits of maximizing liquid production from a gas-lifted field versus recycling the lift gas and constraining the pipeline network capacity.
An important input for gas lift optimization is the volumetric flow rate of injection gas. This data can help experienced Well analysts and gas lift technicians determine if the lift gas injection into the well is optimal in line with advised lift gas rates from models, thus providing directional guidance on what change(s) should be made to improve a well's performance. The volumetric flow rate can be used to estimate the transit time of injected gas, which can then be combined with other tools to determine downhole injection points.
In the Badan field, onshore Niger Delta, with ageing gas lift infrastructure, changes in production rates and fluid properties, there is a need to ensure that real-time lift gas measurements are obtained which allows Production engineers update their flow assurance models and validate new plans. A portable, non-intrusive, ultrasonic flowmeter would be ideal for obtaining the injected gas flow rate in these situations. Clamp-on meters have been around for over 30 years. As a result of improvements in flow metering technology, the last decade has seen clamp-on flowmeters working on a full range of gas applications. Many non-fiscal applications that were done by traditional flowmetering spools are now shifting to clamp-on meters. These meters are cost effective, easy to install, and are proven to be very reliable and accurate. These meters can also be used to monitor gas-lift injection rates during production testing operations to establish a set point for gas lift and achieve maximum hydrocarbon liquid production rates.
In this paper, the results of a pilot trial on the use of a portable clamp-on ultrasonic flowmeter for Gas lift operations/optimization in the Badan field is discussed. Results from optimization efforts in the field has seen a net increase of +/-10% of liquids on a well-by-well basis, which could equal about $200,000 per well per year. A further benefit also includes a reduction in lift gas, which increases capacity within the production piping for additional produced liquids and associated gas. This can greatly impact the bottom-line in a lower-for-longer price environment.
Adaptation of Combined Dual Gradient & Pressure Mud-Cap Drilling Techniques to a HPHT Well- Field Xavier
Authors: Akonye C. K. 
Published: October 2018

Abstract
This paper identifies the potential and limitations of using Dual Gradient Drilling (DGD) combined with Pressure Mud-Cap Drilling (PMCD) in an onshore field where narrow and unpredictable mud weight window was encountered. Some of the world's largest conventional oil fields are located in deep High Pressure, High Temperature formations beyond the earth surface. As the industry engages in these highly productive and promising deep fields, major obstacles are encountered during drilling which leads to high amounts of costly Non-Productive Time (NPT) due to kick or other drilling related problems. With unique challenges such as kick, lost circulation, and narrow drilling windows, there is a need for innovative techniques to develop these fields in a more effective manner.
DGD combined with PMCD is presented as a favorable solution to overcome the challenge of kick associated with a HPHT well in a certain field; Field Xavier, in the Niger Delta. Being able to control the bottomhole pressure profile throughout the wellbore and react to pressure fluctuations, allows drilling to proceed uninterrupted, while keeping the operational problems to a bare minimum. To achieve this, the mud SGs estimated to be used as the heavier mud, ranged from 2.4 SG to 3.7 SG, which will require andinvolve costs in weighting up mud with the use of weighting agents, which are quite expensive, and advanced technology to pump the heavily weighted mud downhole, without mud losses and risks of differential sticking.
For this case study, which was conducted for the Field Xavier onshore production well in the Niger Delta, based on prior measured pore and fracture pressure gradients, the drilling mud program was designed for the two MPD variants; Dual Gradient Drilling (DGD) and Pressure Mud Cap Drilling (PMCD). The onshore well, which has a depleted formation, above a higher pressured formation, is to be drilled with the planned drilling mud program, with 0.319 psi/ft to 0.439 psi/ft for the depleted formation and 0.75 psi/ft to 0.89 psi/ft for the high pressured formation.
This method can be applied in deviated, horizontal and vertical wells, although change in mud volume will have to be accounted for.
Determination of Petroleum Fluid Composition from Separator Information
Authors: Kareem Lateef A. 
Published: October 2018

Abstract
This work detailed the procedure employed in inverse calculation of gas composition using separator information. Starting with flash calculation, we develop a method to determine the separator measurement (Condensate gas ratio (CGR), Gas specific gravity (γg, air = 1.0) and Oil specific gravity (γo, water = 1.0)) given the gas composition and separator operating condition(temperature and pressure).
Unlike previous methods such as described in [1–4] that rely on laboratory experiments data such as normal boiling point (Tb), density (ρ), refractive index (η) and carbon to hydrogen weight ratio (CH) to predict petroleum fluid composition, this new method uses the most basic and easily available information to compute the fluid composition. The composition sort as well as C7+ molecular weight and specific gravity (w.r.t water) are used as parameters of a model that predicts the separator gas gravity γg, condensate liquid gravity γo and condensate gas ratio CGR. Using this model to create an objective function that measures the disparity between the observed separator measurement and the model estimation, we used a Matlab implementation of the Particle Swarm Optimization Methods [5] to search the parameter hypercube (for each gas type: wet gas, gas condensate, and volatile oil as identified by [6]) that minimizes the disparity between measured and estimated values of CGR, γo and γg. We were able to compute the gas composition and Molecular weight and specific gravity (w.r.t water) of the C7+ that gives almost the same gas condensate ratio, oil gravity and gas gravity as the input.
New Milling Solution for Flapper Valve Removal on E-Line in Dry Well Environment
Authors: Dulic Almir 
Published: October 2018

Abstract
In 2017, offshore North Africa, a well in a dry environment utilized a new application of e-line milling technology in combination with a specialized bit to mill out a failed flapper. This was the first time this special bit with the e-line milling toolstring was used to mill out a flapper valve in a dry environment. With this paper the author will describe the history behind the milling bit design, the actual operation and production improvements.
A gas well experienced a malfunctioning 7"x 4.56" 13 Cr. steel downhole flapper valve. Due to several operational challenges including limited well site access and temperatures over 150°C, there was a need for an alternative solution to mill the valve and allow access below it to re-perforate the well.
The operator's method of choice was an e-line tractor and milling assembly that had previous success in the same area in similar conditions. Furthermore, a new milling bit was developed that drastically reduces milling debris and eliminates potential fishing runs. Finally, heavier intervention methods like coiled tubing were not possible to mobilize because of the weather conditions plus the risk of reservoir damage if introducing fluids required to mill on CT
After the completion of the milling phase of the operation, another run was performed to set an access sleeve in the milled-out flapper valve utilizing an electromechanical setting tool. This access sleeve ensured that entry/re-entry through the milled flapper valve would be easily accomplished each time. The installation of the access sleeve was confirmed by first running a drift to TD, followed by the perforating guns toolstring and re-perforating the well.
Milling of flapper valves and other well bore obstructions on electric line offers a cost efficient alternative technology to existing methods. Furthermore, it provides HSE benefits and logistical advantages by reducing the amount of required equipment and personnel.
Increased Production and Restored Wellbore Access Using E-Line Milling Technology, With Enhanced Health, Safety and Environment
Authors: Abdesselam Youcef Ait , Tazairt Reda , Dulic Almir 
Published: October 2018

Abstract
An operator in Algeria, found that when attempting to put wells on production, the lock mandrels were found to be stuck in the nipple profile. All slickline attempts failed to retrieve the mandrel. When coil tubing was deployed, one plug remained stuck in its nipple, while the second one came off its seat only to get stuck inside a Side Pocket Mandrel, about 25m shallower. The sequence of pulling and jarring resulted in both fish necks coming apart, thus rendering all subsequent fishing attempts impossible. Therefore, a decision was made to attempt to mill the mandrels using the new e-line milling technology. Another challenge was that the 2.562″ and 2. 75″ ID mandrels were made of 13 Super Chrome, and there was limited experience milling these types of completion components. Also, due to a rush mobilization, there was no time to execute a SIT. The solution presented consisted of milling first the mandrel outer sleeve, then milling the inner sleeve from the plug body which will cause the mandrel anchoring system to collapse.
Special 2.2" and 2.375" milling bits were manufactured and sent to location. The e-line tractor conveyed the toolstring to target depth where the e-line milling tool was activated and milled through the mandrel sleeves, releasing the anchors. On the first well, the 2.562″ mandrel sleeves were removed using a 2.2″ bit, while the sleeves on the 2.75″ plug were milled using a 2. 375″ bit. With the sleeves removed, slickline ran in hole with a combination of magnets and scratchers (wire brush) of different sizes and fished the remainder of the plug. With full bore access on both wells, and after performing a clean-out operation, the operator could increase the gas production by 100%. This was the first time the e-line milling toolstring was used to mill and remove a lock mandrel.
This paper will review a new application of e-line milling technology to remove heavy duty lock mandrels in order to allow wellbore access and improve the production.
Choke and Well Line Up Optimization in an Intelligent Deepwater Field: Agbami Case Study.
Authors: Okpani Olu , Momoh Victor , Oyewole Anthony 
Published: October 2018

Abstract
Agbami is a prolific deep-water field which commenced production in 2008 and achieved peak production a year later, in 2009. Plateau production has been maintained in the field since 2009 through various efforts which include drilling of additional wells, pressure maintenance by gas and water injection, acid stimulation and choke/well-lineup optimizations. This paper focuses on the production optimization in the Agbami field obtained from choke and well-lineup optimizations.
Agbami production system is an intelligent network that comprises of completions, wells, subsea flowlines and risers. Currently there are 24 wells, 8 subsea flowlines and 8 production risers in the production system. Multiple wells flow commingled in each riser, but each well can be lined-up to either of two risers in a riser loop. Parameters such as pressure, temperature etc. are monitored in real time at different nodes in the network. Production optimizations are achieved by manipulating the production control chokes at the completions, wells or risers; and/or by changing the line-up of the wells.
Robust surveillance and monitoring are key to achieving successful production optimization. Periodic production tests are done at the completion, well and commingled riser level; while periodic pressure build-ups are done on the completion level. These surveillance data (plus real-time data) are used to update the completion, well and riser constraints and to calibrate the production network model. By continuously monitoring the operating constraints and comparing the constraints with the current production data, optimization opportunities are routinely identified. The identified opportunities are evaluated using the calibrated model and if viable, are proposed for execution. The key challenge is having good calibrated production network model to use for optimization.
Choke and well lineup optimizations have proven to be an effective approach to obtaining increased production at no cost. These efforts have led to an average production gain of 12,000 BOPD per year in the past 8 years in Agbami field.
Realligning the Nigerian Gas Master Plan NGMP to Achieve Domestic Gas Supply Sufficiency
Authors: Tahir Salahuddeen M. , Sheriff Ali M. 
Published: October 2018

Abstract
The Federal Government of Nigeria based on its sizable gas reserves, identified the need for accelerated development of the gas industry as a focal strategy for achieving the national aspiration of aggressive GDP growth.
The Nigerian Gas Infrastructure Blueprint which is part of the Nigerian Gas Master Plan (NGMP) approved in 2008 by Nigeria's Federal Executive Council (FEC) is key to its successful implementation. The blueprint consist of a network of three transmission pipelines, three Central Processing Facilities (CPFs) within three delineated franchise areas and wet gas gathering lines to feed the central processing facilities.
The Nigerian National Petroleum Corporation (NNPC) which is the driver of the gas Infrastructure blue print has from 2010 to date, completed and commissioned over 540 KM of gas pipelines. Some of these pipelines were developed based on recent developments. Other critical pipelines are also expected to come on stream before end 2018.
Nigeria's in-country midstream gas infrastructure capacity is estimated at 2.9Bscf/d which can not support the 2018 projected domestic gas demand of 3.38Bscf/d (National Gas Requirement (NGR) Working Committee, October 2017).
The major essence of developing gas CPFs is to create industrial gas development hubs to stimulate economic development. None of the three (3) planned CPFs as contained in FEC's 2008 approval has progressed to an appreciable level. In fact, all MoUs signed for development of the facilities have expired. Issues surrounding the non-actualization of the CPFs border around costs and gas supply.
This paper aims at highlighting the challenges towards implementing the Nigerian Gas Infrastructure Blueprint and proffer solutions to achieving the Federal Government's gas development aspirations. The resultant effect will unlock several opportunities for the country. Other developing countries with sizable gas reserves can take a cue from the paper in developing their individual domestic gas markets.
Effects of Rock and Fluid-Property Heterogeneities on SAGD Performance
Authors: Lawal Kazeem A. 
Published: October 2018

Abstract
To reduce computational costs and accelerate business decision-making, it is not unusual to downplay reservoir heterogeneities. In particular, the evaluation of steam-assisted gravity drainage (SAGD) and other thermal floods may be premised on a homogeneous reservoir, saturated with a heavy-oil of uniform properties. However, virtually all realistic formations are characterised by some spatial variation of rock and fluid properties, even over relatively short intervals. Therefore, to have a good understanding of the physics of oil recovery by SAGD, it is imperative to assess the sensitivity of this recovery process to common heterogeneities in rock and fluid properties. Employing three-dimensional, multiphase and multi-component numerical simulations, this paper tests the robustness of SAGD process to the vertical variation (layering effect) of some rock and fluid properties in a tar-bearing sandstone system. Here, the reservoir properties considered are absolute and relative permeabilities as well as thermal conductivity. On the fluid properties, vertical variation of oil viscosity is investigated. At initial conditions, the resulting vertical contrast of mobility along the heavy-oil column is about three orders of magnitude. In the cases examined, SAGD performance is found sensitive to rock and fluid-property heterogeneities. Permeability (relative), oil viscosity and rock-conductivity contrasts are observed to have significant impacts in the examples investigated. As a result, it is recommended that all heterogeneities should be properly captured at the appropriate scale to ensure realistic rationalisation and prediction of the performances of SAGD and similar thermal recovery processes.
An Analytic Study on Flowline Hydraulics as an Impairment Mechanism of Water Injectors
Authors: Lawal Kazeem A. 
Published: October 2018

Abstract
Considering its potential negative impacts on oil production rates and recovery, injectivity decline in water injectors can lead to significant erosion of project value. Although injector impairment is often related to subsurface-related factors, flowline hydraulics has been identified as a ‘soft’ mechanism of injector underperformance. However, compared to its subsurface counterparts, less attention has been given to flowline hydraulics as a cause of underperformance of water injectors, especially where multiple injectors share a common flowline. While complex network simulation models can be used to evaluate this impairment mechanism, computational costs and interpretation of the attendant simulation results can be worrisome.
To understand the dynamics of the subsurface-surface network of a water injection system without resorting to a complex model, this paper documents an aggregated-network approach, premised on the concept of a "super well". The super well reflects the aggregate reservoir, wellbore and surface hydraulic behaviours of the relevant wells, thus simplifying a complex network of injectors connected to a common reservoir and flowline system. Mathematical formulations of the hydraulics of the aggregate network are prescribed, and solved analytically.
As an illustration of this idea, a practical example is presented. The simulation results show how the injectivity of the super well vary with subsurface conditions plus the number and characteristics of injectors on the flowline at any time.
Among other contributions to the current body of knowledge, this work offers a simple and quick approach to assess the impacts of reservoir conditions, well count, well interactions, well conditions, injection pump pressure, and flowline characteristics on the aggregate and individual behaviours of water injectors sharing the same flowline. More important, the simulation results enable proper discrimination between surface and subsurface factors when evaluating possible underperformers in a network of water injectors.