bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of ISO 14001 Certification in the Transformation of HSE Management in Oil and Gas Industry in Africa
Authors: Mustapha Adetoun , Ezenwaka Israel , Amadi Amadi 
Published: August 2015

Abstract
The 1992 United Nations Conference on Environment and Development (the Earth Summit) recognized the need for businesses to invest in environmental stewardship beyond regulatory requirements. In response to this, the International Standard Organization (ISO) a non-governmental organization that formulates technical and management standards, introduced the ISO 14001 environmental standards in 1995. As at 2013, ISO had 164 members, each representing a country with about 22% from Africa. The ISO 14001 standard requires participants to establish Environmental Management System (EMS) that is verifiable externally. Participants are required to pass an initial certification audit and subsequent annual recertification audits conducted by approved and accredited third-party organizations.
In 1996, Shell committed to external certification of its EMS, initially with EC EMAS (Eco-Management and Audit Scheme) and later with ISO 14001 EMS. Shell in Nigeria developed a phased approach to ISO 14001 certification of its operations, starting with the Alakiri Gas and Oil production facilities in 1997, with the goal to maintain transparency, demonstrate visibility and leadership commitment to continuous improvement in environmental performance.
This paper reviews the value added and lessons learnt from ISO 14001 implementation in Shell Nigeria. It assesses the company environmental performance prior to certification and 15years after, and the overall impact on Health Safety and Environment (HSE) management. Also, it takes a look at how ISO 14001 impacts management of HSE across the industry in Africa and discusses the challenges and opportunities offered by voluntary environmental governance vis-à-vis effectiveness of traditional style of government regulation and compliance driven approach.
Improving Oil Recovery from a Matured Waterflood Reservoir by the Integration and History Matching of available Pressures, Production and Fluid Saturation/Fluid-Contacts
Authors: Okpani Olu , Ambastha Anil 
Published: August 2015

Abstract
Even though the solutions of numerical reservoir simulation are pressures, production rates and fluid saturations; rarely are the fluid-saturations/fluid-contacts included in the history-matching process. History matching to all the available pressures, production rates and fluid saturations/fluid-contacts should increase reliability of a simulation model for forecasting. This history-matching concept was applied to a matured waterflood reservoir (H).
The H reservoir was discovered in 1970. It is vertically divided into two main zones (HA and HC).The reservoir started production in 1971 and has been under peripheral water injection since 1984. Nine producers and one injector have been completed in the reservoir. Currently only two producers (HC-104 and HA-111) and one injector (HAC-53) are active in the reservoir with a current recovery factor at 51%.
The H reservoir was history matched to the following observed data set: RFT pressure (4 wells), static well pressure (9 wells), flowing wellhead pressure (2 current producers), allocated well production (9 wells), and Fluid-Contacts/Fluid-Saturations (8 open- hole logs). History matching of the flowing wellhead pressure, which was done using flowtables, helped to resolve the gas-lift injection volume in well HA-111.
The simulation study was initially done without rigorous attempt to match historical fluid contacts from open-hole logs. Even though reasonable production/pressure match were obtained in some of the wells, the model produced excessive water in well HA-30 and could not achieve water breakthrough in well HC-104. The simulation was then improved by actively history matching the fluid-saturation/fluid-contacts from historical open-hole well logs. Good history match was obtained for pressures, production and fluid-saturation/fluid-contacts in the wells. This resulted in the identification of one new drill opportunity and three workover opportunities with a potential to increase the estimated recovery factor to 64%.
Geomechanical Assessment of Fault Slip and Top Seal Integrity for a Deepwater Turbidite Field Development
Authors: Arogun Olubunmi , Fokker Peter 
Published: August 2015

Abstract
Depletion and injection induced pore pressure changes will be accompanied by total stress changes in the reservoir and around faults which can cause fracture formation or fault activation that may result in fluid migration outside the reservoir. 3D geomechanical assessment of the Deep Water Turbidite (DWT field), located in the southern part of the Niger Delta in offshore Nigeria, was performed in line with subsurface process safety requirements, to determine the sealing integrity of the top seal and the likelihood of the major faults to slip under depletion/injection induced pore pressure changes during the production life of the field. The analysis was carried out using a proprietary Finite Element tool, based on TNO-Diana Finite Elements. A subsequent sensitivity study was performed to account for uncertainties in some of the material parameters used for the assessment.
This paper presents the workflow and outcome of the geomechanical assessment carried out for the DWT field. Model results indicate that faults do not get triggered unless injection pressures can access the entire interval of the fault slip zone, including overburden and underburden sections. Analysis of planned injection pressures in the shallowest layers indicates a potential for hydrofracturing the shale caprock. A mitigation plan is currently being designed to address the issue.
Improving the CO2 Fracturing Effect with Nanoparticles in Shale Gas Reservoir Stimulation
Authors: Li Yanzun , Li Xiangfang , Zang Jiali , Li Zhennan , DiCarlo David 
Published: August 2015

Abstract
Gas production from low permeability unconventional reservoir is still a challenge to the world. Hydraulic fracturing has been successfully applied in unconventional gas production, such as shale gas, tight gas. For its limitations of hydraulic fracturing, liquid CO2 has been pumped as fracturing fluids into unconventional reservoirs. And various additives have been applied to improve CO2 fracturing effect. This paper present an experiment with nanoparticles to evaluate its effect on CO2 fracturing.
The experiment, liquid CO2 was injected into the core to drainage brine or nanoparticles solution to simulate the fracturing process. And CO2 distribution and pressure drop data were real-time measured with a CT scanner and pressure transducers. A significant difference had been observed between with and without nanoparticles. These observations suggest that a nanoparticle-stabilized foam is formed between CO2 and nanoparticle solution, which suppress the viscous instability. Also, the nanoparticles could flow into the nano-pore of shale as proppant to generate more fractures in matrix.
The experiment provide nanoparticles are effective to enhance the CO2 fracturing. Also, it suggests an optimized protocol of CO2 fracturing with nanoparticles in unconventional reservoir stimulate.
A simple aggregate parameter for comparing waterflood reservoirs
Authors: Tetegan Gerard , Lawal Kazeem A. , Tendo Fidelis 
Published: August 2015

Abstract
Waterflooding is a proven method for improving offtake rate and ultimate recovery from conventional-oil reservoirs. Although relatively simple and inexpensive to operate, the dynamics and eventual performance of waterflooded reservoirs are controlled by complex interactions of several factors. Due to this complexity, it has been difficult to develop a robust, consistent and yet simple normalizing parameter for comparing the performances and recoveries of different reservoirs under waterflood. As they are generally empirical, most of the existing analogue techniques are not internally consistent and, under certain conditions, yield non-physical results. The inconsistencies in the analogue techniques are a major challenge in the industry.
This paper reviews common analogue techniques, highlighting their relative strengths and weaknesses. Employing a combination of analytic formulation and numerical simulations, a new aggregate parameter is introduced for characterizing waterflood reservoirs. In addressing the limitations of existing approaches, the new parameter incorporates the key subsurface and operating factors, including well count and reservoir-compartmentalization, which control reservoir performance.
Although developed for waterfloods, the parameter accounts for depletion drive; often the main drive mechanism in cases of delayed as well as inadequate injection. Despite its robustness, the proposed parametric expression remains compact and auditable, while offering a good basis for interdisciplinary discussions and gaining relevant insights.
Using a deepwater turbidite oilfield in West Africa as a case study, applicability of the new aggregate parameter is demonstrated. In this five-reservoir application, the most suitable analogue among the set of reservoirs is identified. Subsequent reservoir-simulation studies affirm the suitability of the recommended analogue and the aggregate parameter.
In practice, the proposed parameter should find applications in establishing analogy for reserves booking, preliminary evaluation of mature waterfloods, sense-checking reservoir-simulation results, and providing insights into realistic reservoir-scale recovery factor. In addition, it is a promising quantity for screening between enhanced-oil and improved-oil recovery opportunities in mature waterfloods.
Reservoir Permeability Evolution in Sand Producing Wells
Authors: Ibukun Opeyemi , Tovar Juan , Heinemann Niklas , Chalmers Frances , Mokdad Belkhir , Katoozi Kia 
Published: August 2015

Abstract
Reservoirs in the Niger Delta oil province are predominantly weak sandstones and unconsolidated sands of the Agbada formation. Wells in these reservoirs are susceptible to sand production as production entails high water cut. Sand production is triggered by mechanical failure near the wellbore and occurs when the near-well deformation process changes. The deformation process is controlled by parameters such as production rate, drawdown, reservoir pressure changes and reservoir formation properties. Mechanical failure of the reservoir leads to the mobilisation of failed material and changes the near wellbore porosity and permeability of the rock.
The Chestnut Field operated by Centrica Energy and partners (block 22/2a, Central North Sea, UK sector) has been under production since 2008 despite continuous sand production. The reservoir consists of unconsolidated sand with a porosity average above 30% and permeability of 0.5 to 2 Darcy similar to many Niger Delta sand reservoirs. This paper introduces the Sand Production and Pore Pressure Management Program which was implemented to control sand production and maintain hydrocarbon production. Additionally, an analysis of near wellbore porosity and permeability changes is presented.
Real-time data acquired from four wells over a period of more than four years and the production of over 140 tons of sand were utilised. The results indicate a change in porosity and permeability which is consistent with a change from compaction to dilatancy conditions near the wellbore. These changes have had a significant impact on the sand management strategy implemented to optimise the production through the field life to date.
Use of Water Injection Surveillance as an Effective Reservoir Management Tool
Authors: Mayowa Sunmonu Rasak , Yewande Shokoya , Paul Okwudiafor , Sheriff Jabar 
Published: August 2015

Abstract
Water injection is aimed at maintaining the reservoir pressure so as to optimize oil recovery. An essential key to a successful water injection project is a comprehensive surveillance process which provides for effective reservoir management.
After detailed preliminary studies and upon implementation, many water injection or water flood projects are known to produce water much earlier than originally anticipated or its full benefit not being harnessed due to out of zone injection as a result of subsurface heterogeneities. Thus, it is important that water injection is managed effectively to ensure its full potential is realised.
In this work, a multilevel and integrated system of surveillance is established to enable proper monitoring of a water injection project through the use of several classical diagnostic plots. The diagnostic tools include the popular VRR plot, Hall plot, Chan plot and ABC plot. The use of grid map plot is also employed to track the displacement and fluid movement within the reservoir.
Two Niger Delta fields under Water Injection are tested with this model and the results presented. The tool proved reliable in identifying bottlenecks within the system, understanding reservoir performance, identifying infill drilling opportunities and improving ultimate oil recovery.
In the recent wake of dwindling oil prices, it becomes incumbent on reservoir engineers to seek methods of optimizing production at minimal cost. This paper illustrates how practical application of good surveillance practise can be used as an effective tool in deriving maximum benefit from a water injection project.
A Real-Time Integration of 3D+ Geo-Mechanical Model to Optimize Mud Weight Across Weak Bedding Plane (A Field Applocation)
Authors: Adetoye Babagbemi S , Dosunmu Adewale , Boniface Oriji A 
Published: August 2015

AbstractBedding plane is a surface that separates one stratum, layer, or bed of stratified rock from another and represents interruptions in the course of deposition of the rock mass. A number of models have been proposed in the attempt to solving the problem of wellbore instabilities due to weak bedding plane. Some of these models are developed to be used at the planning and design stages of the well while the accuracy and efficiency depend largely on the integrity of pre-drill data. The objective of this paper is to provide an integrated 3D+ geo-mechanical model that would help reduce non productive time (NPT) by combining minimum drilling conditions across weak bedding plane, time dependent brittle creep of rocks and optimum hydraulics parameters. The new model assumes anisotropy rock strength criteria in order to develop theory and models to predict rock physical behavior under specific load conditions. Also all in-situ stresses were assumed principal and directed horizontally and vertically. Analyses were achieved with the aid of DrillMax software newly developed and the results validated with Opti-Well software currently in use for the Niger-Delta Field. The intermediate hole section between 8000ft-12500ft of well-1 in the field was investigated. Analysis of the normal compaction trend showed that the well encountered abnormal pressure at the depth of (8500-11500ft). The sensitivity analysis of the field data showed that the overburden pressure lied within the range 16.84- 17.92ppg while pore pressure was between 9.86- 10.91ppg. The fracture pressure was between 12.84- 13.95ppg while the collapse pressure was 10.92-11.68ppg equivalent mud weight. From the analysis of the hydraulics parameters, the pressure drop at the bit was estimated to be 1894Psi. The developed 3D+ integrated geo-mechanical model fell within optimum mud window and integrates time dependent brittle creep of rock and optimum drilling hydraulics.
Micro-storage State and Adsorption behavior of Shale Gas
Authors: Zhao Tianyi , Li Xiangfang , Zhao Huawei , Dou Xiangji 
Published: August 2015

Abstract
One of the important research directions of shale gas is its adsorption mechanism. The focus of the current work is to describe micro-storage state and select the accurate adsorption model.
Micro-storage state of shale gas under different thermal maturity of shale gas is described from the perspective of shale gas accumulation. In organic pores, methane molecules behave as competitive adsorption with water molecules. Inorganic pores are surrounded by water molecules or movable water, in which only a few amounts of methane molecules is dissolved. Based on the simplified local-density (SLD) model, the mechanism of shale gas micro-storage state in different pore size is analyzed. In addition, the adsorbed distance is divided. There have been multiple models for shale gas adsorption behavior prediction. These models were first reviewed, and then their applicabilities were comparative analyzed. An important conclusion of the current work is that Langmuir-Freundlich models fit best, no longer the simple Langmuir model, which is most popular used.
Analyzing the micro-storage of shale gas and selecting accurate fitting models can not only benefit the accurate predicting productivity, but also help understanding the mechanism of adsorption indirectly.
Experimental Investigation of a Niger Delta Hydrocarbon Field for Reservoir Souring Tendency
Authors: Bella Mmata , Olorunfemi Owolabi , Imo Ukut , Mike Onyekonwu 
Published: August 2015

Abstract
Reservoir souring which occurs due to an increase in hydrogen sulfide (H2S) concentration of a production well stream fluid undergoing water injection for example during secondary recovery, can significantly impact on the economic viability of a deep water project. Souring also raises technical concerns ranging from compromising safety compliance to damaging of infrastructure integrity due to corrosion attack. The activities of Sulfur Reducing Bacteria (SRB) present downhole act on sulfate in the injected water (sea water) to enhance the reproduction and generation of hydrogen sulfide which sours the reservoir.
In this work, experimental study was carried out in an XYZ field in the Niger Delta, to evaluate the souring potential of the reservoirs undergoing water flooding. Field test kits were used to determine the temperature, pH and salinity of produced water samples; while colorimetric method was used in the laboratory to determine the sulfate concentration. The strength of stained tubes was used to determine the hydrogen sulfide concentration in the gas phase. The concentration of H2S in one of the wells was as high as 140ppm in the gaseous phase, the salinity concentration ranged between 16,435–24,479mg/l, the sulfate concentration ranged from 0-2200mg/l while the temperature ranged between 31.6°C-62.4°C. The results of the study show a favourable disposition for SRB to thrive and multiply. Also, the reservoirs within the field show different degrees of souring. The outcome of this analysis will be used for proffering cost effective and efficient remedial action.
Fluid Contact Movement Monitoring in Gas Reservoirs using Pressure Transient Data: Galaxy North Field Example.
Authors: Nnadi Magnus , Osho Rotimi , Chima Emelle , Ekeh Obi 
Published: August 2015

Abstract
Pressure transient tests have been used for many years for the determination of well and reservoir parameters. Initially analyses of the tests were limited to evaluation of well performance. With the introduction of computer and pressure derivative log-log plots, numerous signatures of well reservoir and boundary responses are diagnosed and their model parameters estimated. Of recent, controlled reservoir monitoring from either permanent downhole gauges or standard bottom-hole pressure tests especially in gas reservoirs show that gas-water contact movement can be detected from the late time pressure derivative responses hence, water breakthrough time could be predicted. For a historical pressure transient tests taken at different times, the superimposition of their different pressure derivatives on the same log-log plot enable detection of advancing water front. The estimated fluid contacts from subsequent tests can be used to calculate gas volumes/reserves and predict water breakthrough time for the gas wells. This process was applied in Galaxy North field. The Field is a major domestic gas supplier for power generation in Nigeria and it started production in Dec 1963 with oil wells, while the gas wells came on-stream in 1984. Four gas wells have been drilled to in the field date. Current production is at 10Mbopd and 50MMscf/d from oil/gas and gas reservoirs. Pressure transient test are routinely carried out in the field to understand reservoir dynamics and gas wells performances and to ensure proper production planning towards uninterrupted gas supply to domestic market.
The pressure transient tests carried out in Galaxy North wells between 2004 and 2013 depicted responses characteristic of upward trend (pseudo no-flow boundary). The boundary was established to be due to the effect of advancing gas/water contact. The estimated gas/water contact was compared with open-hole saturation log of an infill well drilled in June 2012 and results were close. This was used tovalidate the results of the pressure transient analyses.
This paper presents guidelines and best practices on the use of classical reservoir tools in monitoring the gas water contact and the information derived could be used in estimating gas reserves and predict the future performance of the gas wells to ensure effective gas delivery to customer.
Surfactants Selections Criteria for Enhanced Oil Recovery in High Temperature and High Salinity Environment
Authors: Adeniyi A. T , Onyekonwu M. O , Olafuyi O. A , Sonibare L. O 
Published: August 2015

Abstract
Surfactants are used as suspending and foaming agents. Crude oils deposited and found in sandstone and high temperature environment are often very light. But, Pore throats restrictions made it difficult for such oil to flow unaided. Specially designed surfactants, called IbileSurfac, will serve as a carrier to crude oil, while overcoming barriers posed by saline water. This study was primarily conducted on locally sourced surfactants, called IbileSurfac. IbileSurfac, together with Tween 80, Teepol, and Lauryl Sulphate were screened with NaCl-only brines and n-octane fluid at a unitary value of water/oil ratio for temperatures between approximately 900C and 120°C; at intervals of 5°C. All test cases were performed in the absence of methanol or ethanol (No alcohols present) and other co-solvents, in a Pressure-Volume-Temperature cell. Both volume and pressure were kept constant. Varying phase behavior was observed for each class of surfactants, with minimum salinity value of 0.001parts per thousand and maximum value of 0.002 parts per thousand of NaCl for IbileSurfac and others. IbileSurfac has highest Oil solubilization, and lowest in Teepol, with Tween 80 and Lauryl Sulphate, maintaining middle positions. The test results for 120°C at unitary-water-oil-ratio (WOR) show that Ibile Surfac homogenized to form transparent and aqueous single phase liquid, which can flow easily through pore throat restrictions. This provides a useful lead for initial selection of appropriate surfactants for EOR processes. IbileSurfac is very promising because it has a natural structure that needed the least comparative treatment cost for high temperature and saline environment.