bluuebunny/crossref_metadata_2025 huggingface dataset:
The Characteristics and Adjustment Technology of Surfactant/Polymer Binary Flooding in Conglomerate Reservoir
Authors: Gao Ming , Lv Jianrong , Gao Jian , Zhang Shanyan , Wang Qiang , Wang Xiaoguang , Chen Lihua
Published: October 2018

The recovery factor of surfactant/polymer binary flooding field test in conglomerate reservoir is 14.6% now and it will reach to 18% by prediction. Nevertheless, it has not achieved good results in the early stage. Conglomerate reservoir is more complex and special. The method used in sandstone reservoirs can't be used directly in the conglomerate reservoir. In the early stage of SP flooding, the mature injection technique of sandstone reservoirs was adopted, but the phenomenon of high polymer concentration appeared.

The reservoir and porous characteristics of conglomerate reservoir was analyzed by intrusive mercury curve and pore throat distribution. The law of SP flooding was studied by micro experiment and nuclear magnetic resonance. Comprehensive analyses of SP flooding between conglomerate reservoir and sandstone reservoir were conducted, including SP flooding water cut, injecting SP pressure, time of polymer appearing in production fluid, producing polymer speed and incremental oil recovery. In order to find out the law of different type's reservoir moving, the casing logging analyses was carried out.

Due to the presence of the small grain between the large gravels, the distribution of pore and throat in conglomerate reservoir was characterized by two peaks. It was found that the remaining oil after water flooding was mainly in the pores with radius 1-5μm in the conglomerate reservoir.

Because of the existence of the macro pore path, the initial chemical flooding system had a rapid advance, and the effect was obvious seen after the profile control. The molecular weight of the polymer should be appropriately reduced according to the pore and throat sizes of the reservoir after the macro pore path were blocked by large molecular weight polymers. The matching relationship between polymer and reservoir was reestablished, and the molecular weight and injection concentration of the polymer were adjusted, and the effect of oil increasing was obvious.

The most significant new finding was that the SP system realized the utilization of 30-50mD reservoir by casing logging, which reduced the lower limit of SP flooding to 30mD. This is important because the reserves ratio of 30-50mD reservoir account for a large proportion in the conglomerate reservoir.

The SP flooding in conglomerate reservoir is different from the conventional chemical flooding. The novelty of this paper is to find the characteristics and appropriate adjustment method, which will provide the necessary support for future applications.
Enhancing the Foam Stability Using Surfactants Mixtures
Authors: Almobarky Mohammed , AlYousef Zuhair , Schechter David
Published: October 2018

This work investigated experimentally the potential of the mixture of two anionic surfactants to reduce the mobility and enhance the oil recovery by generating stronger foam than that of the individual surfactants. Foams of the Alcohol Alkoxy Sulfate (AAS), Internal Olefin Sulfonate (IOS) surfactants and their mixtures were compared in bulk and in porous media. In bulk, after the foam has been generated by shaking, the foam columns decay was monitored to measure the foamability and foam stability. Furthermore, interfacial tension was measured for all surfactants solutions for explanation purposes and foam stability interpretations. Dynamically, Boise sandstone was used for surfactant-nitrogen co-injection for mobility reduction evaluation and foam viscosity measurements. Finally, the enhanced oil recovery was investigated by conducting core-flooding experiments for foam application after water flooding.

AAS surfactant showed impressive foamability in NaCl brines, but medium to poor foam stability especially with crude oil. On the other hand, IOS was the best in Deionized Water (DW) especially with crude oil, but poor foamability in brine. The synergism was more obvious in brine than in DW. For instance, the mixture provided five times and four times longer foam half-lives than AAS in absence and presence of crude oil, respectively. Dynamically, the foam generation was observed by the pressure drop jump during the surfactant-gas co-injection. The mixture reduced the mobility 13 and 5 times in comparison with that of AAS. Finally, the application of foam flooding as a tertiary recovery process resulted in 7.5% additional oil recovery by the mixture compared with 2.5% for AAS.
Screening New Formulations for Asphaltene Aggregation Inhibition
Authors: Al-Jabri Jaber , Sultan Abdullah , Al-Mutairi Eid , Onaizi Sagheer A. , Merghani Amir , Hassen Islam
Published: October 2018

Asphaltene aggregation is one of the biggest problems in the oil and gas industry for both upstream and downstream processes. It called the cholesterol of crude oil since it can deposit on the reservoirs pores and block it. It can also plug the production tubes and pipelines which could cost millions of dollars. One of the solutions is adding different chemicals such as asphaltene dispersants (ADs) or asphaltene inhibitors (AIs). ADs reduce asphaltene particle size which will keep them in the crude while AIs prevent the asphaltene aggregation by shifting the onset pressure of asphaltene.

In this paper, three different asphaltene inhibitors were tested and investigated thoroughly with different concentrations for heavy Arabian crude oil. Several tests were performed: asphaltene inhibitors efficiency was tested using laser scanner analysis and asphaltene stability was investigated by using spot test method and asphaltene solubility class index.

The results showed that the Arabian crude oil has a high asphaltene content and it reasonably stable. Two of the inhibitors (SF-1742 and AI-410) have showed better efficiency than the third inhibitor (AI- 108) in the inhibitors efficiency test with low optimum concentration.
Full Wavefield Modeling in Anisotropic Media
Authors: Alshuhail Abdulrahman , Golikov Pavel
Published: October 2018

With the increase in accuracy required for seismic exploration one must include more physics in modeling seismic waves. In this paper we extend Full Wavefield Modeling (FWMod) to handle anisotropic media. FWMod is an integral-based approach that model's reflection events. It considers primary as well as multiple scattered reflections. We make use of the pseudo-elastic assumption for the acoustic wave-equation for anisotropic media to simplify the equations and reduce the cost associated with modeling. This introduces anisotropic kinematics into the acoustic wave equation, however this comes with two main limitations.

The first limitation is that a pseudo S-wave is generated when the source is on, or near, an anisotropic layer. The pseudo S-wave manifests as a diamond shaped shear wave. The second limitation is an exponential growth in the solution for negative values of η. Attenuating these artifacts in finite-difference modeling is difficult and, in many cases, suboptimal. However, with a phase shift method such as FWMod attenuating these limitations is relatively straightforward.

The pseudo S-wave can be clearly recognized in the absolute value of the phase shift extrapolator. In this domain it can be identified and attenuated. As for negative values of η, with this type of representation of the extrapolators, one can ensure that we always have evanescent decay rather than exponential growth in the solution. We include the anisotropic kinematics in the FWMod formulation and demonstrate the effectiveness of this method using a synthetic model.
Substitute CRMs for Quality Control Purposes With In-House QCM
Authors: Hzzazi Salem Ahmed , Qmous Abdullah
Published: October 2018

The Southern Area Laboratories Division (SALD) is accredited the ISO/IEC 17025 and is currently implementing a QA/QC program in all Units as part of the Laboratories quality management to monitor and validating of tests results.

Results of quality control analysis are aimed to provide clear and fast information for the Acceptance of analytical results obtained on a batch of test samples. Continuous use of control Material allows estimation of the stability of performance of the instrument, including calibration, Analytical procedure, analyst, and influence of environmental conditions.

Matrix is one of most common interference that effect choosing appropriate QA. The certified reference material (CRM) is not available at all (matching neither matrix nor measured), in additional to that the CRM is too costly to be used for quality control of a larger number of analytical test runs.

For that reason we conducted a study for the water samples collected from the different locations in the field for geo- chemical studies over a period of times to prepare QC for geo-chemical analysis.
Fluid Typing Using Magnetic Resonance Data with High Diffusivity
Authors: Oifoghe Stanley , Sy Rex , Okowi Victor
Published: October 2018

Magnetic resonance (MR) data were acquired in a six-frequency PoroPerm + Light Oil mode in the study well. The acquired data had a low signal-to-noise ratio from midpoint to the top of the logged interval. This ratio could adversely affect the suitability of this data for hydrocarbon fluid typing and saturation computation.

Examination of the detailed quality control plot showed high B-pulse ringing on the two lowest and the third highest frequencies, A-pulse ringing on the two lowest frequencies, and noise on the two lowest frequencies. The affected frequencies could not be used for fluid typing analysis. The reduction in the total number of available frequencies resulted in a high diffusivity, especially in the gas-bearing reservoir sand. High diffusivity caused some of the movable fluids to appear as irreducible bound water. The low hydrogen index of the gas also caused a low-permeability profile.

Despite the failure of some of the acquired frequencies, there was a need to identify and quantify the fluid type in the reservoir. Several fluid-typing techniques where employed to find a suitable technique for this dataset. After trying Multiple Gradient Inter-Echo Time (MGTE) analysis, the Simultaneous Inversion of Multiple Echo Trains (SIMET) module, and a 2D NMR (D-T2) technique, we decided to use D-T2 analysis because it gave results consistent with the gamma ray and density neutron logs. The D-T2 Analysis module is a software implementation of the 2D/3D NMR technique that solves for the T2 and D, or T1 /T2, T2, and D distributions from wireline magnetic resonance data. Often the results are shown in 2D image form by summation of the individual images having different T1 /T2.

The fluid typing result from D-T2 analysis showed the presence of gas and light hydrocarbon. The gas had an average saturation of 70%, while the oil had an average saturation of 65%. The oil viscosity varied slightly with the overburden gradient, increasing from 0.36cP at the top, to 0.55cP at the bottom. Although the resistivity-based saturation was not compared with the MR-derived saturations, the saturation result and other computed results match the average reservoir properties of offset wells within the vicinity of the study well. The results are also consistent with the gamma ray and density neutron logs.
Derived Equation for Skin Due to Restricted Fluid Entry into ICD
Authors: Uche Chukwunonso Ifeanyi , Obah B. , Onwukwe S. , Anyadiegwu C. , Boluwatife O , Bukar I. , Uche Jennifer
Published: October 2018

The use of inflow control devices (ICD) have been used to balance flux around wellbores and also delay breakthrough of unwanted fluid into completions.1-2. Inflow-control devices (ICDs) were developed to avoid coning problems in long horizontal wells. The model for the ICD consists of pressure-drop equations from the reservoir, through the screen, the flow conduit, the ICD nozzle, and into the production tubing, along with pressure drop through the lower-completion system.1-2. This technology has been a common practice in the petroleum industry for many years now. This procedure though has been beneficial especially in highly heterogenous small formations, but however causes some pressure drop which does not contribute to additional fluid inflow into the wellbore and this is seen to be an impairment to the productivity of horizontal wells to some extent. In wells that are equipped with ICD, a precise quantification of this additional pressure drop is of paramount importance to completely identify the existence of damage created around the well bore. Many authors have proposed mathematical solutions that can be used to estimate various pseudoskin factor caused by damage, partial completion, slanted well and perforation. No author has researched about productivity loss or skin that may result from the use of inflow control devices. In this work, a 3D numerical model which includes inflow control devices along horizontal wells was used to investigate reservoir and production performances of various ICD nozzle sizes. Different productivity losses from different nozzle sizes were seen as skin. Consequently, a simple equation for calculating this skin due to restricted fluid entry through ICD nozzles was derived. The skin results obtained from this new equation is compared with the result obtained using existing skin equation and the variance is within acceptable limit.
Techniques for Effective Oil Production from Thin Oil Rim Reservoirs
Authors: Ogolo Naomi Amoni , Molokwu Victor C. , Onyekonwu Mike O.
Published: October 2018

There are several proposed techniques that can improve oil recovery efficiency from thin oil rims with strong aquifers and large gas caps. These techniques include use of horizontal wells, water production from the underlying aquifer, edge water injection into the oil zone and gas injection at the oil water contact (OWC). Since all these methods improve oil recovery from thin oil rims, one of the objectives of this work is to investigate by simulation, the effect of combining two methods on recovery efficiency of the reservoir. The dynamics of the fluid contacts for all the techniques considered were also studied and it was observed that the most minimal shift occurred with the technique of gas injection at the OWC.

Simulation results revealed that combining two techniques does not significantly improve oil recovery efficiency over one technique. When only a single technique was used, the oil recovery factors were 40%, 33% 44% and 42% for water production and disposal, edge water injection, gas injection at the OWC and water injection at the gas oil contact (GOC) respectively. But on combining two techniques of simultaneous water and gas injection at the GOC and OWC respectively and alternate water and gas injection at the GOC and OWC respectively, the oil recovery efficiency were 43% and 45% respectively. These results indicate that any increase that might occur may not be significant enough to justify the cost of implementing two or more techniques; thus, optimizing a single technique is recommended.
Experimental Investigation of Potential of Combined Controlled Salinity and Bio-Surfactant CSBS in Enhanced Oil Recovery EOR Processes
Authors: Udoh Tinuola , Akanji Lateef , Vinogradov Jan
Published: October 2018

In this study, we investigate potential application of environment-friendly bio-surfactants (EFBS) in EOR processes. We assess the prospect of combining the EFBS with controlled salinity (CS) water injection in optimising oil recovery using rhamnolipid and protein-enzyme as case study. Rock component analysis, bio-surfactant solubility in brine of varied concentration and composition, crude oil-brine interfacial tension (IFT) and bio-surfactants emulsification activity test were carried out as part of the preliminary investigations. Following these preliminary analyses, a series of comprehensive core flooding displacement experiments were used to investigate the EOR potential of CSBS injection process. Finally, effluent analyses were conducted to study the effect of this combined process on dynamic oil-brine-rock interactions. Results of the IFT tests using 0.0083-3M brine concentrations show IFT reduction from 3.40-2.5 mN/m with increasing salinity for protein-enzyme while increase in IFT from 0.11-0.34mN/m was observed with increasing salinity for rhamnolipid. However, using a fixed brine concentration of 8.3mM with varied bio-surfactant concentration, IFT reduction with increase in concentration was observed for both of them. Also, the two bio-surfactants exhibited stable emulsion active in varied brine salinity investigated. Protein-enzyme is soluble in varied brine formulation while rhamnolipid solubility was found to be dependent on the brine composition and system pH rather than the ionic strength. Furthermore, from the secondary injection of CS and CSBS, the highest recovery factor of 82.76% was achieved with CSBS (protein-enzyme). However, in the tertiary applications, the highest recovery of 83.40% was achieved in the CS injection. Finally, increased pH, Ca2+ and Mg2+ concentrations was observed with both CS and CSBS flooding. This suggests reaction between excess cations and previously adsorbed carboxylic group of crude-oil led to increased recovery. Whereas, at residual oil saturation, interaction between bio-surfactant molecules and rock surface resulted in increased water-wetness and release of oil.
Innovative Approaches to Successful Narrow Margin Drilling in Deepwater: Planning and Execution Strategies
Authors: Ayodele Adetokunbo
Published: October 2018

Drilling operations in a deepwater environment is faced with several challenges in all phases, and the most common types of drilling problems encountered in deepwater are similar to those found in shallow water or land. Although water depth in itself does not create new sets of problems, it however introduces additional complexities and limits problem-solving options in some instances. The most notable of these complexities is the narrow pore pressure/fracture gradient margin that is frequently encountered in deepwater environments.

The complexity of narrow margin is compounded in mature fields as depletion occurs, regardless of the production support mechanism. In extreme cases, the safe drilling window is narrower or non-existent, and as such necessitates appropriate mud weight selection and careful control of Equivalent Circulating Densities (ECD). Low mud weight can result in a kick or wellbore instability when the radial stress acting on the wellbore is insufficient. On the other end of the spectrum, high mud weight can cause formation fracture, exposing the wellbore to losses and well control event if not properly controlled.

In the late life of the field, it transcends and exceeds the application of conventional drilling methods to deliver an economically viable deepwater well. While drilling with the added complexity of a narrow drilling margin in mature fields, conventional methods tend to be inefficient and cost-ineffective and as such changes in the magnitude of a paradigm shift are required.

This paper presents some innovative approaches that can be employed in managing narrow margin drilling from the planning to execution phase of well delivery. It shows the collaboration and contribution of a cross-functional team in the planning phase, implementation of advanced drilling practices during execution phase and post drill optimization methods to deliver wells safely and within approved budget.
Performance Evaluation as a Tool for Improving Health, Safety and Environment Culture in the Oil Servicing Industry
Authors: Anyanwu Brilliance O. , Elijah Esuuk , Akakranta Onyewuchi
Published: October 2018

The study focused on evaluating the Health, Safety and Environment (HSE) performance of selected Oil servicing companies (X, Y and Z) engaged in Logistics, Mud logging and Engineering services respectively in Rivers State, Nigeria. This aim was achieved by determining the awareness level of Health, Safety and Environment Management System (HSE MS) and performance/practice level of HSE MS respectively.

Two sources of data were both used in this study. The primary source were from questionnaires distributed to 150 participants, out of which 120 were retrieved from 42 participants in company X, 40 in company Y and 38 in company Z representing 80% response rate. The awareness and performance levels of HSE MS were assessed with ten questionnaire parameters each respectively and their judgments rated Yes (3), No (2) and Undecided (1). This Likert approach was to facilitate the evaluation of Kendall's coefficient of concordance (W), representing the concordance level among participants.

The results revealed average levels of awareness (79%) and performance/practice (64%) of HSE MS respectively among the companies except for company Z. Gaps identified included lack of awareness on what governs the integrated HSE MS, lack of provision of hygienic environment and non-availability of safe equipment and PPE. Company Z had deficiencies in providing a good system for communicating HSE issues, providing permit to work (PTW), conducting HSE induction/training, providing incident reporting procedure, ensuring contingency plans are made available and maintaining a good system for managing employee's health. The secondary data source were from the HSE MS Audit unit of the companies selected which showed that company X had an overall performance of 77% which indicated a good level, company Y had an overall performance of 64.3% which is a fair level and finally, company Z had 30% performance level which is unsatisfactory. Kendall's analysis showed a high level of agreement on both awareness (0.90) and performance (0.99) levels respectively.

The study recommends training of employees, provision of an environment with good hygienic conditions, and provision of safe equipment and personal protective equipment (PPE) for all companies. Provisions for contingency plans permit to work (PTW), and HSE review meetings should be emphasized by company Z. The findings and recommendations of this research will be a yardstick to these companies and other related companies in implementing HSE MS as business integration in quality and risk management.
Automation of Electrofacies Identification - A Case for Digitalization
Authors: Isimbabi Onoze A.
Published: October 2018

The 21st century is a period of rapid advancement in technology and the ever adapting and perhaps proactive companies will be the companies of the future. Advancement in science and in this case 3D reservoir modelling requires the automation of repetitive and mundane tasks to liberate human resources for evaluations and actual problem solving.

3D reservoir modelling is the digital representation of the subsurface in other to predict the behaviour of fluids in the reservoir, and a facies model is key to building a robust 3D reservoir model, as it provides the geometry and relationship of the reservoir sub units. The identification of facies in reservoirs as an input to building reservoir models is done using several data types including core data, seismic data, and well logs. This study focuses on the use of well logs in the identification of facies (electrofacies).

Electrofacies are facies defined using a set of well-log responses that characterize a lithologic unit and distinguishes it from others. Standard Industry practice has established the use of gamma ray log signature as predictors of facies and it is this relationship that is explored in this study. In 3D reservoir modelling, the process of facies identification and painting the facies into discrete logs is a repetitive and sometimes harrowing process - especially in a field with several stacked reservoirs and well penetrations. This process takes up valuable time in 3D reservoir modelling and the monotony can also lead to errors that may have a significant impact on the facies model eventually built. At present, the automation available in modelling tools is only able to identify facies using absolute log values; this only discriminates between sandstone and shale in clastic reservoirs.

In this study, I present an excel-based application that can ‘recognize’ log shapes and as such, can identify up to five distinct facies: Channel Sands, Upper Shoreface, Lower Shoreface, Heteroliths and Shale in shallow marine settings. This application has been deployed to build a 3D static model for field development planning for the Debby field, Onshore Niger Delta. Significant results were achieved with execution of facies identification and discrete log creation taking less than 5% of the time it would typically take for manual electrofacies definition. This ensured more time availability for important and productive tasks such as uncertainty analysis, sensitivity analysis, and creation of more recovery scenarios.
Numerical Simulation of Polymer Flooding in a Heterogeneous Reservoir: Constarained versus Unconstrained Optimization
Authors: Ibiam Emmanuel , Geiger Sebastian , Almaqbali Adnan , Demyanov Vasily , Arnold Dan
Published: October 2018

The average global recovery factor of a typical oil and gas field is approximately 40% at after secondary recovery processes such as gas lifting and water flooding. The low recovery factor is often a result of by passing a considerable amount of oil in the reservoir due to unknown reservoir heterogeneity and incomplete understanding of the geology. Enhanced oil recovery (EOR) methods will play a key role in increasing recovery factors from existing reservoirs. Heterogeneous reservoir sands often show permeability contrast between layers and therefore lead to early water breakthrough when water flooding. In such situations, polymer flooding can potentially be a suitable EOR technique that helps to lower water cut and increase recovery. The addition of polymers to the injected water lowers the mobility ratio, thereby reducing viscous fingering and delaying water breakthrough.

This study investigates how a polymer flood design can be optimized while considering geological uncertainty in the reservoir models as well as modelling decisions. We applied an adjoint based technique to match data from a prolonged waterflood in the Watt Field, a synthetic but realistic clastic reservoir that is based on real data and captures a wide range of geological heterogeneities and uncertainties through a range of different model scenarios and model realizations. We apply Latin hypercube experimental designs with the Particle Swarm Optimization algorithm in CMOST. This was used to build a proxy model employing polynomial regression for the optimization of the engineering parameters to maximize NPV. The optimization were performed for both history-matched models (constrained optimization) and the original, non-history-matched models (unconstrained optimization). The aim of this work is to analyse how geological uncertainties inherent to a heterogeneous clastic reservoir as well as modelling decisions impact the design and performance a polymer flood. We further investigate how the different optimization methods impact the predicted reservoir performance and optimal design of the polymer flood.

Our findings show that both, geological and engineering uncertainties, impact polymer flooding and that designing the right well controls is essential for successful polymer flooding. Shale cut-offs are identified as a key petrophysical uncertainty when optimizing a polymer flood in a heterogeneous clastic reservoir. Furthermore, forecasts using constrained optimization yielded a much narrower range of incremental oil recovery and NPV during polymer flooding and may underestimate both, risk and opportunities for polymer flooding because the history matching of the water flood emphasizes different geological features compared to the way geology interacts with a more viscous polymer solution.
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

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

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

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

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

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

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

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

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

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.