bluuebunny/crossref_metadata_2025 huggingface dataset:
Advanced Analytics for Data-Driven Decision Making in Electrical Submersible Pump Operations Management
Authors: Adesanwo Moradeyo , Bello Oladele , Olorode Olumide , Eremiokhale Obehi , Sanusi Sherif , Blankson Eyituoyo
Published: July 2017

Increasing demand for cost-cutting measures has seen the petroleum industry taking advantage of new technology to accelerate production and increase ultimate recovery while maximizing reliability of the production system. Electrical submersible pump (ESP) technologies for in-well and subsea boosting systems have evolved to become a critical component in many production operations. However, ESPs are complex dynamical systems whose performance can be degraded by certain faults or events such as gas locking, changes in fluid characteristics, plugged pump, tubing leak and closed valve.

With the explosive growth of sensor data, it is no wonder that knowledge discovery has grown in importance in facilitating descriptive analyses (clustering) and predictive analyses (regression and classification) applications to ESP operations management. Interestingly, the development of appropriate algorithms to process ESP signals, detect events and prescribe optimal decisions given ESP real-time data and auxiliary, predictive observations have until now largely been overlooked.

This paper presents a decision support system for continuous ESP event detection and providing prescriptive analytics tool to analyze and manage ESP operation performance. The system includes a database management system, a real-time data management architecture, a real-time signals processing engine, forecasting system to forecast instance based on real-time data, outlier detection model, a sequence analyzer for event recognition, a prescriptive analytics to provide recommendations concerning the optimal alternative actions to be executed during events and a graphical user interface to visually analyze the flexibility and prescription model instance. The proposed procedure has been tested in a field to verify the functionalities of the system. The results show that the proposed methodology can be efficiently used in a wide range of electrical submersible pump system operation performance management and surveillance. The results demonstrate the importance of the proposed methodology and adapting it to ESP well production operations.
Techno-Economic Assessment of Mini-GTL Technologies for Flare Gas Monetization in Nigeria
Authors: Kanshio Sunday , Agogo Hezekiah Ogo , Chior Ternenge Joseph
Published: July 2017

Nigeria recently endorsed the World Bank's zero routine flaring by 2030 initiative and raised her own goal to 2020. As a step towards achieving the 2020 flare out goal, the Ministry of Petroleum Resources has established a national gas flare commercialization framework. Under this framework, licenses would be issued to third parties who would become off-takers of the gas. While this framework presents opportunity for investment, most of the oil fields where the gas is being flared may be far from existing pipelines and process infrastructures. Additionally, flare gas is often associated with volume, composition and pressure fluctuations, which make technology selection for its utilization more challenging. This paper reviewed some technologies for flare gas recovery and utilization, and identified promising technologies with capabilities of handling flare gas volume below 1 MMscfd. Mini gas-to-liquid (mini-GTL) technologies for producing diesel, methanol and anhydrous ammonia developed by Greyrock, GasTechno and Proton Ventures, respectively, were selected. The technical viability and economic benefits of these technologies were evaluated based on feed gas rate of 500 Mscfd. While all the technologies are technically viable, the gross profit margin of the GasTechno's miniGTL technology with methanol as the GTL product was found to be more attractive.
Mobilization of Clayey Fines by Different Water Salinity Values in the Presence of Aluminium Oxide Nanoparticles
Authors: Ogolo Naomi Amoni , Iloke Emeka , Godstime Timothy G. , Onyekonwu Mike O.
Published: July 2017

Water salinity is one primary factor that triggers migration of clayey fines in hydrocarbon reservoirs. However, the presence of some agents in the formation can delay this process and Aluminum oxide nanoparticles (Al2O3NP) have been proposed as one of such agents that can control fines migration. The primary objective of this study therefore is to experimentally determine the amount of fines free water effluent (in terms of pore volume) that can be produced from sand packs containing Al2O3 nanoparticles at different levels of water salinity. Another objective is to investigate the optimum sand treatment duration with Al2O3NP in control of fines migration.

The sand samples contained 5% clayey fines obtained from the Niger Delta and a constant flow rate of 3ml/min was maintained for all the experiments which were conducted under standard condition. The amount of Al2O3 nanoparticles used in the samples was 20% of the clay content, but Al2O3 NPs were not used in all the reference experiments. Two different sets of experiment were conducted in this work; the first set of experiment involved flowing various salinity levels of water ranging from 0 – 40g/l through sand packs while the second involved soaking sand in brine for various numbers of days before flowing brine of 5g/l salinity through the sand.

The experimental results showed that Al2O3 nanoparticles have the capacity to control clay mobilization in sands triggered by low water salinity. For the use of light crude at a salinity of 15g/l and 30g/l, about 25pore volumes and 33pore volumes of fines free effluents were produced respectively from the sand samples containing Al2O3 nanoparticles while about 13pore volumes and 21pore volumes of clean effluents were produced for the reference experiments respectively for a bulk volume of sand of about 55cm3. For the use of medium crude at a salinity of 15g/l and 30g/l, about 23pore volumes and 32pore volumes of fines free effluents were produced respectively from the sand samples containing Al2O3 nanoparticles while about 8pore volumes and 13pore volumes of clean effluents were produced for the reference experiments respectively. A comparison of the results of the sand samples containing Al2O3 nanoparticles with the reference results shows that the presence of Al2O3 nanoparticles in sands can control clay mobilization triggered by low water salinity. The results from the second part of the work showed that the maximum volume of clean effluent was recovered on the zero day of soaking. This implies that soaking is not required to achieve effective fines trapping in sand since the performance of fines trapping by Al2O3 NP diminishes with time.
Proposed Technique for Improved Oil Recovery from Thin Oil Rim Reservoirs with Strong Aquifers and Large Gas Caps
Authors: Ogolo Naomi Amoni , Molokwu Victor C. , Onyekonwu Mike O.
Published: July 2017

Oil production from thin oil rim reservoirs with strong aquifers and large gas caps is challenging due to early gas and water breakthrough, movement of the fluid contacts and low oil recovery factor. One means of handling the problems associated with thin oil reservoirs is the use of horizontal wells which improves recovery factor. This work however proposes a measure through which gas injection into the reservoir is used to improve oil recovery factor and minimize water production using vertical wells. A simulation study was carried out using the data from a thin oil rim reservoir in the Niger Delta. The five cases studied are the base case (using conventional vertical wells), use of horizontal wells, water production and disposal, water production and re-injection into the oil zone to improve recovery, and gas injection at the oil water contact.

The recovery factor and volume of produced water were compared for all five cases for a production period of 40years. An oil recovery factor of 25%, 29%, 40%, 33% and 44% were obtained for the base case, use of horizontal wells, water production and disposal, water production and re-injection to improve recovery, and gas injection at the oil water contact respectively. Volume of produced water was lowest while the GOR was highest for the proposed method than any other method. The main disadvantage using the approach of injecting gas at the water oil contacat is the high GOR however; recycling the gas by injecting the produced gas back into the gas cap is a viable solution. The relatively higher oil recovery factor and minimal volume of produced water which are highly desired for effective production from thin oil reservoirs makes the proposed technique worth investigating.
Performance Analysis of Gas Cycling Operation in Retrograde Gas Condensate Reservoir- A Niger Delta Case Study
Authors: Chibueze S. E. , Ibeh S. U. , Onugha I. N. , Obah B.
Published: July 2017

Retrograde Gas Condensate reservoirs are economically valuable assets but constitute a complex system in its management and development. Condensate banking due to liquid condensation below the dew point pressure raises technical and economic concerns in unlocking reservoir potentials. As pressure decreases with production below the dew point, liquid drop out phenomena is inevitable. This has two major consequences for an operator. First, the condensation of liquid/condensates which are immobile and remains trapped in the reservoir pores due to capillary-induced interfacial tension creates a permanent formation damage/impairment signified by a reduction in gas relative permeability and productivity. Secondly, the bulk of heavier and valuable components are lost to the pores of the reservoir rock. In this study, the interactions among fluid flow and reservoir rock properties were integrated in modeling and simulation of a retrograde gas condensate reservoir undergoing gas cycling. Economic evaluations based on reservoir performance indicate that, with gas cycling, a 70% and 90% recovery in condensate and gas respectively with an Internal Rate of Return (IRR) of 41% is feasible.
Extending the Fetkovich Type Curve Approach to Forecast Cumulative Production for Solution Gas Drive Reservoirs
Authors: Olatunde T. E. , Akinpelu L. O.
Published: July 2017

Decline Curve Analysis (DCA) is an important tool used in the petroleum industry to forecast future production performance. Forecasting future production performance is one of the critical inputs in the economic analysis of Oil and Gas investments. Conventional DCA (Arps' approach) has however been shown to have limited accuracy in forecasting cumulative production for solution – gas – drive reservoirs.

Fetkovich introduced a novel method of combining rate equation and material balance equation for finite systems to obtain rate – time equations for solution – gas – drive reservoirs, using the backpressure exponent (n) in place of the Arps' decline exponent (b). This work extends Fetkovich rate –time equation approach by developing cumulative – time and cumulative – rate models, for the two basic forms of the material balance equation investigated viz: PR is linear with Np (or Gp), PR2 is linear with NP (or Gp).

The models developed were validated with production data from two reservoirs, the first reservoir presented in the original Arps' paper and the second reservoir located in Niger Delta, Nigeria. The models were found to provide more accurate forecast of the cumulative production of a solution – gas – drive reservoir than the Arps' approach. The developed models also yielded results which compared favourably with the actual cumulative production data from the solution – gas – drive reservoir in Niger Delta. For the Niger Delta reservoir, the forecasted oil in place gives 128.844MMstb while the actual (estimated) oil in place was 127MMstb, a difference of 1.69%.
Gas Tolling – Low Cost Development Options for Small and Stranded Gas Fields in Nigeria
Authors: Adedamola Adegun , Olalekan Abiola
Published: July 2017

Over 70% of Nigeria's onshore gas resources are dispersed in small and stranded fields across the Niger Delta, making their development uneconomical and exacerbating the gas flaring challenge. It's estimated that about 30 tcf of gas reserves, qualified as ‘low hanging fruits’ were undeveloped over the years due to low domestic gas prices and the huge capital outlay for gas processing and transportation facilities. In recent years, reforms in domestic gas prices have improved the economics and attractiveness of gas monetization projects but the challenge of high CAPEX particularly with the recent industry downturn remains a constraint.

Gas tolling, which involves the provision of gas gathering and processing services by tolling companies to gas producers is a unique solution that has the potentials to transform the domestic gas industry. The extant Nigerian Gas Master Plan (2008) and the draft National Gas policy (2016) recognises the important role of gas tolling and seeks to expand its adoption across the country. Still at its nascence in Nigeria, tolling companies (gas facility developers) and gas resource owners must understand the key value drivers and seek to ensure mutually beneficial and sustainable gas tolling models.

This paper therefore seeks to explore the models available to tolling companies and resource owners, highlight the underlying technical and economic considerations by the parties and also provide options that help parties minimize exposure to fiscal obligations. An economic model useful for evaluating the appropriate compensation options for the tolling company and returns for the gas resource owners is also presented. Understanding the dynamics of third party gas tolling will significantly drive the growth of gas development and address the specter of stranded fields’ routine gas flaring in Nigeria.
Simultatanous Operations SIMOPS for Drilling & Production: The NPDC Ogini-Field Approach Planning to Field Execution
Authors: Chieke Chidi Anselm , Ubani Ndubisi , Obi Chinyere C. , Awa Chidi Uka , Bola Adelanke G. , Modibbo Tijanni , Bello Nura
Published: July 2017

Cluster drilling comes with its own attendant challenges; however, operators usually adopt this option in order to reduce environmental footprint and optimize cost. Drilling additional wells in an existing cluster will require simultaneous operation in order to maximize value. The philosophy underlying the rules for SIMOPS is that the interactions between operations must remain manageable (and can be demonstrated to be so) under all conditions that can be realistically foreseen. This paper focuses on four (4) activities that delivered the Ogini field HSE-Case, whose primary objective was to generate an in-house risk assessment and hazard register for Simultaneous Operations (SIMOPS) involved in drilling of the five (5) new Ogini wells namely:- Operational description of Ogini SIMOPS project, Description of HSE-MS, Risk Assessment and Remedial Action Plan (RAP). The SIMOPS for Ogini-field was limited to those activities associated with oil production from the existing wells, drilling operations and laying of flowlines for tie-in of new wells to the flowstation for production.

The Ogini SIMOPS have several HSE components that require critical review; a multi-disciplinary team was constituted to assess/evaluate the Risks and generate a Hazard register used in Simultaneous Operations Planning (SIMOPS) for the project. The Scope of work of the team included coming up with the industry-acceptable strategies to carry out the following operations simultaneously viz:- Flowline Construction, Rig Move, Well Delivery and Production.

A SIMOPS Planning was developed by NPDC Team and approved by DPR. Five (5) horizontal wells were drilled in a cluster (of 4.5m apart) with two producing wells; hooking up the new wells to production facility sequentially while rig was still on site.

Following the review of the distances between the planned five wells and considering future intervention works in this location, after drilling and completion of first two wells, the rig was skidded some meters further away from the initial surface location to drill the subsequent wells. Extended well test was carried out on these completed wells during this operation. This reduced the identified risks associated with SIMOPS and also provided accelerated returns on initial investments.
Gas Cap Development Guideline: Closing the Gap Between Effective Reservoir management and Contract Obligations
Authors: Nwaokorie Chukwuemeka , Ekong Inem
Published: July 2017

Gas portfolio development and the need to support Nigeria's Gas master plan is currently a high priority effort in government and international companies. Therefore, it is important to have a standardized approach for the development of the Gas Cap reservoirs. This guideline will provide a clear process to support the asset/study team in securing appropriate approvals from the government regulatory body (e.g. DPR) for the development of the gas cap resources.

Gas categorization guideline is adopted as a classification system for the company's gas reservoirs to help demonstrate the timing of availability of gas cap production. The classification is driven by the time remaining to produce the economic ultimate recovery from the oil rims associated with the gas caps and processing plants/evacuation ullage availability.

The objectives of the guideline are: To facilitate development planning and gas forecasting via a transparent picture on what the gas resources categories are. While existing fields mature, the development decisions regarding the oil rims become focused on ever reducing infill drilling targets. It is important to be aware how these decisions impact the availability of the gas cap production. The classification helps to provide clarity and transparency in this respect. This clarity aids to demonstrate the robustness of the Company's gas delivery promise.To help in defining standardized approach in getting approval for gas cap development from Department of Petroleum Resources (DPR). In defining this approach, a concise Gas cap release methodology is developed to guide asset and study teams in taking decisions on Gas cap development.

A clear workflow was developed for Gas Cap Development and subjected to company's internal assurance process.

Proper value assessment is done comparing the oil development and the company's gas requirement. Several sensitivities were carried out on the reservoir gas cap blowdown timing and the total reservoir NPV against the different GCBD timing (Figure1). Figure 1GCBD Optimal Timing Sensitivity
Brown Field Value Realization Via Gas Lift Deployment: A Case Study of NAMUB Field
Authors: Mogbolu Emmanuel , Agbor Etta , Ukeko Onoriode , Briggs Tamunoseleipiri , Ndukwe Agwu
Published: July 2017

The primary focus of a wells, reservoir and facilities management team is to guaranty shareholders value by improving production and optimize recovery. Several best practices abound in the industry to achieve this goal. Some screening criteria are used during integrated field reviews to benchmark identified opportunities and rank/select viable candidates for execution. This screening criteria includes: economic ranking, reserves, doability and regulatory policies. The resulting unconventional study allows for a better reservoir management plan.

This paper presents an integrated methodology utilized to restore oil production for a brown field via gaslift project. This was applied in the NAMUB Field case and the information obtained can be applied on other fields with similar scenarios.

In the case of NAMUB field, the estimation of the incremental oil resource volume was estimated using Material Balance models that are calibrated with pressure data and history matched. The field did not meet up with conventional screening criteria for Gaslift Project. This is due to technical, non-technical and economic reasons.

The field studied is composed of stacked reservoirs that have not had oil production for about ten years. Therefore, it was pertinent that a project had to be executed to restore/ carry out oil rim development. This was further made expedient due to the gas cap blowdown of the reservoirs. The continuous gas development impacted on the recovery of oil and further eroded oil resource volume. This integrated study comprised of Surface Engineering disciplines, Petroleum Engineering/ Geoscience disciplines, Economists and Business Planners.

The outcome of inter-reservoir communication studies and sensitivity analyses was integrated to manage uncertainties leading to robust outcomes. The results obtained were not benchmarked against any previous one, as this was a unique step out scenario the company had to deal with. The performance of the 5 wells will be monitored against actual production to validate the methods and processes adopted in this study.

The integrated approach used in the study across the diverse disciplines allowed for seamless delivery of the project.
Application of Artificial Neural Networks in Predicting Critical Rates for Vertical Wells in Oil Rim Reservoirs
Authors: Owolabi Olukunle O. , Ogungbamigbe Samuel E.
Published: July 2017

Critical coning rate determination as a measure of preventing coning in oil fields with underlying aquifers and overlying gas caps are a fundamental aspect of production planning in field development plans. This has always been carried out using existing correlations having large error margins. This study is aimed at developing a more accurate prediction model based on artificial neural network.

A sensitivity analysis making use of Tornado and Spider plots was used in determining the important input variables and the magnitude of their impacts on critical rates. Twelve variables were determined and were used as input parameters in constructing the network using a feed forward layered network with Bayesian regularization for fit testing to predict critical rates.

The results predicted by the Network averaged in between rates from other correlations for the same set of field data. The Network had a mean standard error of 611.7 which was the lowest when compared to the error generated by other correlations. A large variance was also noted between the rates generated from all correlations for the same data set.

The results above validate the use of the model as a predictive tool in determining critical rates. Exposure of the neural model to a wider range of data from mature fields that have already faced coning problems will be needed to fine tune the network to give even more accurate results. It is recommended that more studies be carried out in determining all variables affecting coning in oil fields.
A Successful Rigless Water Shut Off and Reperforation Operations - A Case Study in NPDC Operated Field
Authors: Adio Jaiyeola T , Ajah Gerald E , Akeremale Ayodeji T , Chee Kin Khong
Published: July 2017

As oil fields mature, more wells produce at higher water cut and consequently hydrocarbon production decline. These wells cease to flow overtime due to increased water encroachment. The declining wells and associated facilities are valuable assets that need to be effectively and optimally utilized throughout the producing life of the fields. Remedial actions through water shut-off techniques have been successful in reviving these wells and this has helped immensely in increasing oil production and revenue by reducing OPEX incurred in managing high water production.

At this period of low oil prices, operators are devising strategies of increasing production while saving cost through the use of old (existing) wells to target new reservoirs and optimizing existing perforation intervals as against drilling new wells.

Adoption of the above strategies in some NPDC operated fields has remarkably increased revenue and saved cost.

This paper presents a case scenario of a well in one of the fields operated by NPDC where a rigless intervention operation using coil tubing was carried out to shut-off water production from a zone with cement plug. Subsequently, an oriented re-perforation operation was performed on more prolific shallower (New) zones using electric line unit.

The success of the job was attributed to proper problem diagnosis, job design and execution using reliable and state-of-the-art technologies.
Adjoint-Based Assisted History Matching: A Niger Delta Field Case Study
Authors: Onwuchekwa Chukwuma , Dennar Linda , Ahmed Suleiman , Bakare Olatunji , Emelle Chima
Published: July 2017

Reservoir models are calibrated with production and pressure data to provide some confidence in the prediction of future reservoir production using the models. The last two decades have witnessed the proposal of numerous computer-assisted history matching techniques to ease the laborious task of reservoir model history matching and the related task of uncertainty analysis. Although many of these proposals have proved not to be viable when tried on real (i.e field) cases, some, such as experimental design, are now routinely used in the petroleum industry for history matching and uncertainty analysis. One notable, but largely under-utilised, technique that has generated a lot of interest for application to history matching is adjoint-based optimization.

This paper discusses a field example of the application of the adjoint technique with experimental design to match the historical production and pressure data of a Niger Delta oil rim reservoir with a huge gas cap – the "SWX" reservoir in the "Beska" Field. The "SWX" reservoir, which is one of the few oil reservoirs in the gas-dominated "Beska" field, has been on production since 1992. A decision was to be made on the best time to commence gas cap blow down without jeopardising the life cycle hydrocarbon recovery from the reservoir. A properly history matched model of the reservoir was required for this decision.

Adjoint technique was deployed to assist with the history matching of the "SWX" reservoir which had previously proved difficult to history match. The technique was applied both in the model-maturation stage for improved understanding of the reservoir and the final stages of the history matching exercise to fine tune the history matches of some difficult-to-match wells. The exercise provided an opportunity to test the merits and limitations of the adjoint technique. The result of these tests will be discussed in this paper.
Incorporating the Principles of Decline Curve Analysis in Solving Issues With Paucity of Production Data While Carrying Out Material Balance Modeling
Authors: Okechukwu Sedoo , Oluwajuyigbe David , Unukogbon Obaro , Egwim Stella
Published: July 2017

Material balance analysis is a proven technique for quantifying reservoir performance. Reliable material balance analysis requires accurate pressure and production data amongst other things. In cases where complete production data is not readily available, estimating reservoir performance properties such as pressure and fluid contacts which is needed to support further field development can be a serious challenge. This paper shows how the issue of scarcity of production data can be managed to enable proper reservoir analysis to support further field development.

The paper focuses on a case study on the Ibaba reservoir where paucity of production data is a key uncertainty. The Ibaba reservoir is a Niger Delta reservoir with two parts, Part A and Part B. Both parts have been produced simultaneously from the field for over 40 years. There is a need to carry out material balance analysis on the reservoir to estimate the current fluid contacts to support Short Term Oil Generation activities (STOG). This exercise required production data from inception to the current year 2016. However, for the wells produced in Part B of the reservoir, complete production data was not readily available. To solve this problem, complete production data was generated by performing decline curve analysis on the available production data. A robustness check was carried out and this gives confidence in the results obtained.
How to Drive Contractor Performance and Save Millions
Authors: Okenyi Kingsley , Apena Abayomi , Mba Ognane Edgar F
Published: July 2017

To achieve superb performance in drilling, one should look at the major causes of failure and tackle them head on. That was exactly what was done in Nigeria. In collaboration with directional drilling contractor, the Shell Nigeria Exploration and Production Company (SNEPCo) Wells (Drilling and Completion) team brought losses due to non-productive time (NPT) from millions of dollars down to zero in only a little more than three years.

SNEPCO's non-productive time (NPT) values was considerably high which resulted in the drilling and completions of only three wells. This performance was not sustainable and something had to be done.

The strategy used to turn things around and as reported in this paper was to Define and accurately measure NPT and inefficiencyHave a pre-defined performance metrics or KPIRoot Cause Analysis Investigation, Implementation of Learning and Continuous Improvement.Effective Collaboration and People Management
A General Approach to Production Forecasting of Long-Term Reservoir Performance
Authors: Mohammed S.
Published: July 2017

Arps’ empirical equations have gained widespread acceptance due to their explicit nature and the ease of applicaton of the equations to field data. The major challenge, however, is that the analyst needs to have a prior knowledge of the type of decline (whether exponential, hyperbolic or harmonic). This has long been a major concern because not only is the Arps’ decline exponent difficult to estimate, but also an erroneous estimate of the decline exponent does have a significant adverse effect on the predicted rates and estimated reserves. The traditional efforts to solving this problem encompass type curves analysis with several values of Arps’ decline exponents; a trial-and-error technique; rate derivative plots and assumption of a minimum decline rate. Unfortunately, type curve analysis is subjective and non-unique, trial-and-error method is time-consuming, and rate derivative data are almost always noisy.

This paper proposes a general approach that can be used to forecast long-term reservoir performance without a prior knowledge of the type of decline. The proposed approach couples the rate-material balance time relation, which was previously developed by Palacio and Blasingame, and the rate-time exponential equation. In particular, the rate-material balance time relation is used to estimate the input parameters of the rate-time exponential equation. The theoretical basis for coupling the rate-material balance time relation and the rate-time exponential equation is presented. Models for estimating the ultimate recovery and productive life of the reservoir are also presented. The validity of the rate-material balance time relation for any types of rate decline renders the proposed approach general in its applicability; consequently, the proposed approach will enable engineers to apply a single unique method to predict long-term reservoir performance regardless of the type of decline. Simulated and field data are presented to demonstrate the utility of the proposed approach.
Analysis of Post-Drill Pore Pressure and Fracture Gradient Model of G-Field, Offshore, Niger Delta
Authors: George C. O. , Thomas S. W. , John M. , Gani A. , Emmanuel A. K. , Norbert A. E.
Published: July 2017

Post-drill pore pressure and fracture gradient analyses were carried out in an offshore hydrocarbon field, of Niger DeltaBasin, the G-field, using petrophysical logs, drilling parameters and pressure data. Four wells were analyzed and the results from the analysis will serve as a look back in building a Pre-Spud pore pressure and fracture gradient model for future drilling of exploration and production wells. The overburden gradient and normal compaction trend were generated based on an empirical formula. The pore pressure gradients were computed using the Eaton’s and Miller’s method respectively. Mud weights, drilling parameters and drilling events were used to calibrate the pore pressure gradients. Fracture gradient was computed using Mathews and Kelly’s method with pore pressure definitive, overburden gradient and effective stress ratio as the inputs. Based on the empirical methods, pressure transition zones were detected across the four wells with three (3) pressure ramps of magnitude of 1.23 ppg (Pound Per Gallon), 2.55ppg and 1.52ppg respectively. Pore pressure gradient model generated from the study revealed normally pressured zones at the shallower part of the unconfined section in all the wells within the range of 870 and 6273 feet TVD (True Vertical Depth) with an average shale pore pressure of 8.4ppg for Well 1,4715 and 9145 feet TVD with an average shale pore pressure of 8.5ppg for Well 2, 2614 and 7736 feet TVD with an average shale pore pressure of 8.39ppg for Well 3 and 4227 and 7972 feet TVD with an average shale pore pressure of 8.4ppg for Well 4. The top of the overpressured zones (>0.47 Psi/ft) (9ppg) were established across the four wells. The analysis of pore pressure of the field shows that the depth to the overpressured zones ranges from 7498 to 8859 feet TVD for Well 1,9825 and 13582 feet TVD for Well2, 7741 and 12264 TVD for Well 3 and 8307 and 12220 feet TVD for Well 4.
Fast Tracking Field Development Optimisation With Nature Inspired Heuristics
Authors: Ilamah Osho , Ebere Maurice
Published: July 2017

Wells are a crucial element in any field development optimisation effort. A field development will not be optimal unless we drill optimum types and number of wells, at optimum locations in the reservoir. Traditionally, a manual trial-and-error approach is taken for field development optimisation. The manual approach allows the engineer to exercise full control over the process, which can be beneficial when the engineer is very knowledgeable, but this approach is very inefficient and unreliable. Increasingly, stochastic optimisation algorithms are being applied to identify optimal or near optimal well configurations. For typical field development optimisation problems, these stochastic algorithms require many thousand objective function evaluations, in the form of reservoir simulations, and this is a major issue.

In this paper, we demonstrate an alternative approach to field development optimisation. It starts with one or more sets of candidate wells, with associated type, location and trajectory information. Iteratively, elimination of wells is performed based on a simulation derived well valuation metric. The elimination of wells corresponds to a modification of the development well configuration (well count, locations and well types). Therefore, by comparing the field level valuation metrics obtained across iterations, we can determine the optimal development well configuration. Our approach focuses the optimisation search only on the promising areas of the solution space, represented by the initial candidate well sets, or starting well configuration. Determination of locations and trajectories of the initial candidate wells is therefore key. In our work, we determine the locations and trajectories of initial candidate wells using patterns, potential estimates and an Ant System.

Two examples are used to illustrate the effectiveness of our approach. The results show that the approach significantly speeds up field development optimization, allowing simultaneous optimisation of well locations, well count and well types.
Use of Petro-Elastic Analysis to Evaluate Potential for Sand Production in Petroleum Reservoirs
Authors: Ukaonu Cyril , Odubanjo Teleola , Lawal Kazeem A. , Eyitayo Stella I. , Ovuru Mathilda I. , Anyadike Emeka , Matemilola Saka
Published: July 2017

Sandstone formations that have potential to produce sand during the life of the well account for a significant fraction of global recoverable volumes of oil and gas resources. The economics, environmental and safety implications of sand problems are critical enough to justify good knowledge of the potential for sand failure and production. Reliable evaluation of potential sand production is required to identify the needs for and the specification of sand-exclusion equipment during the project execution phase.

To address these challenges, this paper presents a simple workflow that is premised on the petro-elasticity of the formation. Specifically, the proposed workflow uses cross plots of compressional sonic logs and density logs on reservoir-by-reservoir and well-by-well basis. From a petro-elastic standpoint, compressional sonic logs contain information on travel time required for sound waves to travel through the subject formation. The fundamental relationship between formation compaction (strength) and porosity has been explored to establish the trend of compaction, hence vulnerability of a sandstone formation to failure.

In illustrating the applicability of the proposed concepts and workflow, some field examples from the Niger Delta are presented. Using wells with known history of sand failure and production, the workflow has been applied retroactively. The methodology presented is very useful for establishment of a quick screening sand control requirement. From a qualitative standpoint, it is found that the performances of the proposed workflow are in reasonable agreement with the history of sand failure and production in the example wells.
Smart Well Completion Design using Feed-Through Swell Packers in a Gas Well: A Case Study
Authors: Adejoke Adebayo , Hamzat Kassim , Laoye Abiodun , Cosmas Nwankwo , Iyengumwena Ricky , Nnadi Magnus
Published: July 2017

Smart well technology allows production acceleration from multiple completions and value realization from otherwise marginal reservoirs. Critical to the success of a smart well completion targeting more than one reservoir is the proper design selection and reservoir isolation to prevent cross flow.

This case study describes the selection of a suitable gas well design from different available options, the considerations made in the design selection which incorporated the different completion components, one of the components being the feed-through swell packers which is its first use in the company, to achieve reservoir isolation. The paper also describes the execution of the selected completion design in one of the cases, as well as the testing of the well to verify reservoir isolation, and confirm the effectiveness of the feed-through swell packer.

The selected completion design was cost effective, reduced operational / deployment risks (compared to other isolation options) and had no adverse impact on well productivity of the wells. It also achieved the objective of accelerating the recovery of a combined volume of 221 Bscf of gas from marginal gas reservoirs in a field.
Standard Operating Procedure for Analysis of Oil Rim Occurrence & Viability in Gas-Down-To Reservoirs
Authors: Ikpera Cordelia , Ekong Inem
Published: July 2017

Nigeria has over 180 Tscf of gas resource volumes to support its export and domestic gas demand. Significant quantity of these resource volumes are associated with reservoirs encountered in down dip oilrim with varying oilrim thicknesses or in Gas-Down-To (GDT) situation requiring appraisal and justification prior to gas development which may lead to restriction on gas readiness.

Unlocking these gas volumes is key to maintaining gas supply and meeting contractual obligations. Therefore, this paper presents a Standard Operating Procedure (SOP) which provides a structured approach and workflow for analyzing and managing the uncertainty of potential oilrim below known GDT reservoirs and evaluating the technical producibility and viability of the oilrim reservoirs. It also discusses the different methods currently being used in the industry, applications and boundary conditions in estimating hydrocarbon fill below know GDT and highlights results of blind test analysis carried out for five wells drilled in the Niger Delta. The application of this SOP provides a quick assessment guide to aid timely decision on gas field development without necessarily drilling an appraisal well thereby saving huge cost especially in this era of low oil price and funding challenges.

The SOP adopts an integrated approach and involves the use of available geoscience and engineering data to estimate fluid contact below known GDT. It takes into account the environment of deposition, reservoir depth, historical knowledge and production data to estimate contact and oilrm viability. Minimum data required for each analysis is detailed in the SOP workflow and methodology outlined for ease of adaptation.

These methods are reliable techniques and should not be used in isolation but to compliment the other. Results from blind test analysis for five wells selected for this study demonstrates a potential savings of $60 MMUSD from drilling a minimum of two appraisals wells and enabled a timely decision to be taken for the development of the gas reservoirs leading to maximimzation of cash flow and NPV.
Grain Size Effect on Permeabilty and Pressure Drop in Alkali-Surfactant-Polymer Flooding
Authors: Onuoha Sean O. , Olafuyi Olalekan , Taiwo Oluwaseun
Published: July 2017

In order to improve the efficiency of the enhanced oil recovery process, researchers have come up with different methods such as mobility control, chemical, miscible, thermal and other processes such as microbial. In chemical flooding for example, alkaline, polymer, surfactant, surfactant polymer (SP) and alkaline surfactant polymer (ASP) have all been employed in the quest for better efficiency. However, grain size effect on the recovery system during these tertiary recovery techniques has received less attention over the years.

This paper presents evaluation of the effects of grain size on residual oil saturation (ROS) from experimental studies of oil recovery potentials of a formulated ASP slug in synthetic porous media. 1% weight of sodium hydroxide (NaOH), 0.15% weight of shell enordet 0242 supplied by shell research centre and 0.02% weight of hengfloc 63020 were used as alkali, surfactant and polymer respectively. Ranges of core grain sizes of 0.063 to 0.090, 0.106 to 0.150, 0.150 to 0.212, 0.212 0.300 and 0.425 to 0.600 micron were considered in five different experiments performed. Each of the experiment was accomplished by a procedural sequence of brine saturation, oil saturation, water flooding and ASP flooding.

The results show that the porosity of the synthesized core increases with decreasing grain size from 37.2% to 43.74% for a range of 0.600 micron to 0.063 micron of sizes. The permeability of the synthetic core decreases from 2309 millidarcy to 669 millidarcy as the grain size decreases from 0.600 micron to 0.063 micron. Pressure drop across the beads pack increases from 0.294 psi to 1.015 psi as the grain size reduces. The oil recovery by an immiscible fluid through the beads pack increases as the pore throat get smaller or the grain size reduces. The volume of ROS after flooding reduces as grain size reduces.
Arborização do Campus IV da Universidade Federal da Paraíba, Rio Tinto, Paraíba, Brasil
Authors: Gomes Sofia Erika Moreira , Reis Scheila Najara Silva dos
Published: July 2017

O Campus IV da Universidade Federal da Paraíba (UFPB) foi implantado em 2006 e é dividido em duas unidades, localizadas nos Municípios de Mamanguape e Rio Tinto, no Estado da Paraíba. Este estudo foi desenvolvido no Campus de Rio Tinto, que apresenta uma área de 40.893 m2. O objetivo foi inventariar as espécies arbóreas e analisar suas interações com o entorno. Também foram coletadas informações como porte, altura da primeira ramificação, diâmetro à altura do peito (DAP) e o afloramento da raiz. As coletas foram realizadas de maio a setembro de 2011. Foi registrado um total de 45 indivíduos, distribuídos em 14 espécies e 10 famílias, onde a maioria é exótica. O porte variou entre 3,02 m e 12,84 m. A altura da primeira ramificação acima de 1,8 m teve um percentual de 26,7%. O DAP abaixo de 0,5 m foi de 73,8%. O afloramento da raiz foi observado em 24,4% das árvores. Observou-se que 6,7% das árvores estavam em contato com a fiação elétrica, 4,4% encostavam nos postes, 6,7% bloqueavam a iluminação, bem como 22,2% estavam em contato com muros. Concluiu-se que o Campus IV da UFPB, quando comparado a outros campi brasileiros possui pouca quantidade de árvores.
Quantum Gross-Pitaevskii Equation
Authors: Haegeman Jutho , Draxler Damian , Stojevic Vid , Cirac Ignacio , Osborne Tobias , Verstraete Frank
Published: July 2017

We introduce a non-commutative generalization of the Gross-Pitaevskii
equation for one-dimensional quantum gasses and quantum liquids. This
generalization is obtained by applying the time-dependent variational
principle to the variational manifold of continuous matrix product
states. This allows for a full quantum description of many body system
—including entanglement and correlations— and thus extends significantly
beyond the usual mean-field description of the Gross-Pitaevskii
equation, which is known to fail for (quasi) one-dimensional systems. By
linearizing around a stationary solution, we furthermore derive an
associated generalization of the Bogoliubov – de Gennes equations. This
framework is applied to compute the steady state response amplitude to a
periodic perturbation of the potential.
Niveles de empatía y ética profesional en candidatos a sub-especialidad médica
Authors: Jiménez-López José Luis , Arenas-Osuna Jesús , Ángeles-Garay Ulises
Published: July 2017

La percepción actual de una atención médica deshumanizada y de baja calidad ha cuestionado la capacidad empática y ética de los profesionales de la salud. Las investigaciones en este campo reportan fluctuaciones en estos atributos a lo largo de la formación de los médicos. Objetivo: Explorar los niveles globales de empatía y ética profesional, así como los niveles de cada componente de ambos atributos, en una muestra de candidatos a subespecialidad médica. Metodología: Se incluyeron 65 residentes que solicitaron cursar subespecialidad en una unidad médica de alta especialidad. Como parte del proceso de solicitud, respondieron el Test de Empatía Cognitiva y Afectiva y la Escala de Actitudes Éticas Profesionales. Resultados: Las puntuaciones promedio de la muestra calificaron como media en empatía y como óptimas en ética profesional. La comparación por género, especialidad y competencias mostró menor empatía afectiva y mejor competencia ética en las mujeres; mayor empatía cognitiva en subespecialidades quirúrgicas; y ausencia de correlación entre las dos variables en general, y en particular por competencia. Conclusiones: Se resalta la importancia de medir las competencias particulares de cada atributo dado que la variación en competencias específicas repercute en diferentes aspectos de la formación del médico, como la elección de especialidad, la selección de candidatos, la elaboración de programas académicos y el adecuado aprendizaje sobre la construcción de una efectiva relación médico-paciente. © Revista Colombiana de Ciencias Sociales.