bluuebunny/crossref_metadata_2025 huggingface dataset:
Impact Of Reversible Invert Emulsion Drilling Fluid Rheology On Productivity
Authors: Okoro E. E. , Dosunmu A. , Oriji B. , Iyuke S.
Published: August 2015

Drilling muds are multi-component fluid systems designed to perform several functions during drilling operation and as a drill-in fluid under varying conditions of temperature and pressure. The use of conventional oil-base mud for drilling can bring with it an associated trade-off in formation damage. For a drilling engineer, oil-base muds control reactive shales, improve penetration rates and enhance overall drilling efficiency. For a reservoir engineer, the oil-wet state of the wellbore and filtercake may present a skin challenge. Reservoir productivity impairment resulting from using oil-base mud takes many forms. It may relate to plugging of completion equipment and gravel packs by poorly displaced oil-wet filtercake. Due to this oil-wet state, oil mud filtercakes and other oil-wet materials deposited during the drilling process are not easily dispersed or removed by cleanup chemicals. Emulsions composed of non-dispersed oil mud and displacement fluids often remain within the wellbore. During production operation, the flow from thereservoir can mobilize these oil-wet materials, plugging completion equipment and pore space. This may significantly impair well performance regardless of its design purpose. The most obvious solution for avoiding oil mud related productivity impairment would be to drill the formation with water-base mud. However, drilling engineers often use oil-base muds to minimize risk and efficiently reach extended drilling targets. The problems associated with oil-mud filtercake cleanup and change over operation during completion operations has prompt this study. Operators and service companies develop and apply novel technologies to improve drilling efficiency and maximize hydrocarbon recovery. This paper presents a review on the principle behind formulation and development of reversible mud with nano additives that will eliminate the hard choice that the drilling engineers have to choose between improving drilling performance and decreasing the risk of completion impairment; they can have both requirements in a single mud system.
Application of Uncertainty Management in a Brown Field using Reservoir Simulation: A Case Study of SPDC's Field Re-Development
Authors: Etokakpan Eteobong , Keme Bomo , Nwonodi Chike , Amogu Daniel , Orekoya Adedoyin , Longe Victor , Olubamise Taiwo , Ukauku Ikwan , Nworie Ejiuwa
Published: August 2015

Managing uncertainties during subsurface modelling in brown field re-development requires robust identification and quantification of impact of the underlying uncertainties. Within a given cycle of integrated reservoir modelling, a modelling strategy can only be defined based on associated uncertainties and development options. This paper focuses on using the Design of Experiment to screen and quantify the impact of uncertainties and evaluate development outcomes in a brown field.

The paper details steps taken to identify and quantify subsurface uncertainties in a multi stacked reservoirs that could impact development options. The overall development strategy was to: (a) Introduce artificial lift and offtake management to keep existing wells flowing, (b) Install gas lift supply lines from new gas-lift skid at the flowstation to existing wells requiring gas-lift, (c) drill and complete additional wells using existing locations, (d) hook up the new wells to existing remote manifold and route to flowstations via existing bulklines. To access the impact of uncertain parameters and its ranges of uncertainty were identified and quantified based on current understanding of the reservoirs. The Plackett-Burman Design of Experiment was used to screen each parameter using the Tornado and/or Pareto Plots. The key uncertainties (heavy hitters) identified from the screening stage were carried forward to develop a Response Surface Model (RSM) using Box-Behnken experimental design in order to sample the full uncertainty space associated with each reservoir. The probability distributions of In-Place and cumulative production were generated using Monte-Carlo analysis and estimate of the Proved, Probable and Possible volumes and ultimate recovery were obtained (part of methodology)

From the study results, the feasibility for further oil and gas development based on 3D reservoir simulation with several development scenarios and options were evaluated. Results of the deterministic possible outcomes were used to identify specific cases that closely matched the Proved, Probable and Possible volumes from the Monte-Carlo distribution. Model provides tool for better well and reservoir management.
CO2 Capture & Utilization: Harnessing the CO2 Content in Natural Gas for Environmental and Economic Gains
Authors: Agiaye Emmanuel O. , Othman Mohammed
Published: August 2015

CO2 capture and utilization (CCU) is currently a global topical issue, and is viewed as one possible route to reduction of CO2 concentrations in the atmosphere. The core issues of development, economy and the environment which the world faces in current times are identified to be dependent on the provision of clean, efficient, affordable and reliable energy services. Presently the world is highly dependent on fossil fuels for provision of energy services, and the amount renewable energies can sufficiently replace is minimal. The deployment of appropriate CO2 separation technologies for the processing of natural gas is viewed as an abatement measure towards global CO2 emissions reduction. Selection of the optimum technology among the several separation technologies for a particular separation need requires special attention in order to harness the economic and environmental benefits. The captured CO2 would also require appropriate disposal or utilisation so as to prevent or ‘delay’ its re-entry into the atmosphere. These challenges of CCU involving natural gas particularly during processing which has become an area of intense research shall be discussed in the paper with respect to the selected technique for CO2 capture. A typical natural gas production scenario in Nigeria shall be analysed for potential CO2 capture. Further discussion shall be on the identification of the recovered CO2 gas utilisation framework such as CO2 flooding (in Enhanced Oil Recovery) for additional revenue generation, assessment of the CO2 savings and the contribution to the clean development mechanism (CDM).
Evaluation of Oil Spill Dispersants with a focus on their toxicity and Biodegradability
Authors: Nwaizuzu C. , Joel O. F. , Sikoki F. D.
Published: August 2015

Oil spill dispersants (OSD) are known to be efficient tools needed to clean and disperse many oil spills. Dispersants are used to disperse oil and prevent them from reaching the shorelines. There are two major concerns in the use of dispersants on our environment. Their toxicity, because the synergistic toxicity effects of these chemicals is of great concern as different chemicals that combine together in the same effluent can have toxic effects even when each of the individual chemicals is known to be non-toxic. Also their biodegradability, as every product whose final fate is in our environment should biodegrade quickly in order to avoid irreparable damage and disruption of the natural ecosystem. This work reviewed literature on oil spill dispersants from 1994–2014 focusing on their toxicity and biodegradability. From the review, many researchers however reported that dispersed oil is more toxic than the crude oil while very few were able to show that the dispersed oil was less toxic or equal in toxicity to the crude oil. They also showed that the dispersant increased the concentration of PAHs in the water column, this some accredited to be the cause of the increased toxicity. The effect of the toxicity on the various organs of the organism was noted as some recorded lesions on the gills of fish, drop in heart rate and so on. Many studies proved that dispersants do actually increase the biodegradability although to some it was restricted to some components of the crude oil. Some researchers however showed that the dispersant reduced the biodegradability of the crude oil. Also noted was the fact that various crude oils reacted differently when mixed with a dispersant and aquatic organisms reacted differently to different combinations of the dispersed oil. Temperature was shown to play a role in rate of biodegradability. More work needs to be done here in Nigeria to determine the cumulative impact oil spill dispersants have on the different organisms in the ecosystem when mixed with our various crude oils. Since the window of opportunity for use of a dispersant after an oil spill is recorded to be between hours to 2 days, this will aid timely decision making on the use of dispersants in our waters.
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

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

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

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

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

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

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

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

Bedding 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

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

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

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

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.
Full-Field History-Match of Stacked Reservoirs across Fault Blocks to Investigate Cross-Fault Block Communiation
Authors: Jeboda Olatunji , Ambastha Anil , Eme Vincent
Published: August 2015

A stacked series of fault juxtaposed reservoirs across four fault blocks in an offshore field were being considered for further development, but communication across fault blocks remained an uncertainty even after 40 years of production from these reservoirs. Providing a reliable forecast associated with a development plan required understanding of the impact of these faults to the reservoirs’ historical production and how it may impact future development opportunities. A full field simulation model containing all the reservoirs in the field, which can capture the impact of the communication across the fault blocks was built but due to the large number and coarse scale of grid blocks as well as mulyiple reservoirs, it was decided to use the results from the pressure-match work done on the full-field model and work with smaller, but finer scale, full-field simulation models with less number of reservoirs which were more likely to be communicating to produce a model which could answer these questions and provide a reliable forecast associated with the development opportunities.

This paper describes a full field, three-dimensional, three-phase, black-oil simulation model of several reservoirs in Bayelsa field (not real name) which was used to investigate across fault block communication and identify further development opportunities in these reservoirs.
A Time Function Havlena and Odeh MBE Straight Line Equation
Authors: Buduka Stanley , Biu Victor T , Sylvester Okotie
Published: August 2015

The straight line model introduced by Havlena and Odeh require plotting of the underground recoverable function F against the oil plus dissolved gas expansion function Eo or gas cap expansion function Eg or the connate water and rock properties Efw or a combination of these drives depending on the existing reservoir drive. The consequence is that the estimation of the initial oil in place and cumulative oil produced do not considered the timing factor of the average production of the field life. Hence, this paper present an alternative Havlena & Odeh model in which the reservoir functions such as F are plotted against E per cumulative time making reservoir engineers to appreciate the reservoir behaviour at each time space/limit and also act as a check to the original Havlena and Odeh model. The average production per day is used as against the cumulative production. An appropriate equation and method of analysis is show in this paper. Nevertheless a practical field case is considered. Result from the new model maintained relevant trend with the old Havlena and Odeh model with error factor of 0.043%, hence suitable for predicting reservoir performance as a function of time and also estimating initial oil in place and cumulative production.
From Exploration to Development: The Value of Formation Pressure While Drilling Applications
Authors: Okoroafor Rita Esuru , Nkanga Akanimoh , Okoli Fanyama , Babatunde Folasade , Danison Idang , Akinnagbe Timothy
Published: August 2015

The varied applications of formation pressure data analysis have been realized using state-of-the-art acquisition methodology. The methodology which involves customized workflows in order to achieve the objectives for Formation Pressure While Drilling (FPWD) acquisition has reduced stationary time, improved data precision, ensured better depth management and reduced tool lost-in-hole.

The case studies are wells located in various offshore and deep-water fields in the Gulf of Guinea. Well types include exploration, appraisal and development. Well architecture includes vertical, slightly deviated and highly deviated wells. The objectives for FPWD in these wells ranged from optimizing drilling, formation evaluation, understanding extent of depletion, acquiring information for completion decisions, and ultimately to aid in safe well drilling.

In one of the exploratory wells, the FPWD tool was used to validate wireline formation pressure measurements. The study not only shows that there were cost savings in this methodology, but also reliable information about the reservoir was available in real time to make critical decisions before the bottom-hole-assembly was pulled out of hole. In one of the appraisal wells, data obtained while drilling enabled safe drilling to total depth (TD) with optimum mud weight, and also effectively determined fluid types and contacts. In the high-angle development wells, FPWD was effectively used to gather information to aid in reservoir characterization and management.

This paper demonstrates the suitability of FPWD applications in exploratory, development and production wells. It also shows how cost savings can be achieved by deploying formation-pressure-while-drilling technology for drilling-related applications, formation evaluation and reservoir management.

The paper also demonstrates the flexibility of FPWD for different well architecture and well conditions. Having the data in real time aids in quick operational and completions decision making based on the objectives of acquiring the data.
Impact of the National Content Act on Deep Water Offshore Development in Nigeria
Authors: Echendu J. C. , Iledare O. O.
Published: August 2015

The key objectives of National Content Act (NCA) of 2010 in Nigeria aim to enhance operational efficiency and drive costs down in the medium to long term by encouraging indigenous participation and ownership of assets in the oil and gas industry. Its implementation in the industry is to facilitate the industrialization process by manufacturing and fabricating components and other requirements needed in the industry locally. The Act is expected to stimulate investments and create opportunities for Nigerians to participate in the oil and gas industry in Nigeria.

The passage of the NCA in 2010 and the subsequent formation of the Nigerian Content Development and Monitoring Board (NCDMB) have facilitated the emergence of indigenous companies operating in both the upstream and downstream sectors of the petroleum industry. Certainly, some achievements have been made in terms of policy guidelines, usage of made-in-Nigeria pipelines, increased in-country fabrication tonnage, employment and training strategy to mention a few; yet about 90% of the industry annual budget is still spent abroad. This signifies that much more could still be achieved than accomplished thus far.

This paper investigates the implications of foreign expenditure as proposed in the Petroleum Industry Bill 2012 (PIB 2012) in Nigeria. The paper also evaluates the likely impact of national content contribution to the national economy. Further, the paper examines the effects of the negotiable limit of deductible foreign expenditure on project performance using Discounted Net Cash Flow (DNCF) model framework.

It is observed that as the expenditure domiciled locally increases, the contractor Internal Rate of Return (IRR) increases with a corresponding higher value added to the investment than otherwise, assuming the homogeneity of a dollar spent abroad and locally. The marginal increment to the contractor in terms of IRR or Net Present Value (NPV) is higher in comparison to the marginal effect to the mineral owner in terms of Discounted Government Take (DGT), ceteris paribus. It is, however, recommended that a range for the negotiable limit be specified to avoid an open-ended discourse. Investors are seemingly better off if they reduce foreign expenditures and purposefully engage and develop national capacity as evident.
Low Salinity Water Injection for EOR
Authors: Chandrashegaran Premkumar
Published: August 2015

Low Salinity Waterflooding is one of the emerging oil recovery techniques which has gained its popularity in the past decade. Many experiments and laboratory works have been conducted since its oil recovery potential was discovered in late 1960s. Wettability alteration in the reservoir is said to be the main cause in enhancing oil recovery. Nevertheless, the effectiveness of this type of oil recovery is very much dependent on the initial reservoir conditions, in particular, the connate water saturation, rock physics and connate water salinity. This work is to run simulations on ECLIPSE 100 simulator to show the effect of injecting low salinity water into a reservoir. A simple static model was created to mimic a real reservoir. Reservoir is of three phase with oil, gas and water and consists of one injector and one producer just to simulate the effect of injecting a low salinity water and a normal salinity, or seawater. Effect on oil recovery was observed by conducting sensitivity studies on rock physics; both injection and reservoir brine salinity; tertiary recovery option; polymer injection using low salinity water solution; and grid refinement. A difference of 14% in oil recovery is observed when lower salinity water is used to inject compared with normal salinity water. The effect on oil recovery also showed distinct difference when the connate water salinity is changed with difference up to 28% with low saline reservoir water. Polymer injection with low salinity water gave 4% increment in recovery compared to injecting with higher salinity water for the same concentration of polymer. This can indeed give better cost savings when opting for polymer injection, where a lower concentration or amount of polymer is needed with the use of low salinity water.
Abang Field: An Integrated Approach to Maximizing Volumes Growth
Authors: Alim Chimereucheya N. , Ajibola Olayode , Udoh Isonguyo
Published: August 2015

The Abang field located Offshore Nigeria was discovered in 1992 and commenced production in 2012. The field consists of a 3-way structural closure on the footwall of a very large regional down-to-the-basin growth fault and Deepwater Confined Channel Complex (CCC) environment of deposition.

Key uncertainties in the field include the lateral stratigraphic continuity of the reservoir and the degree of communication across the shales separating the sand intervals. The seismic quality in this region is fair and the pre-development geologic / simulation model is inadequate to address post-drill learnings.

Early post-production dynamic pressure data indicated that observed pressures were higher than predrill estimates. This led to several Material Balance (MBAL) analysis based on a range of Aquifer-Hydrocarbon ratios (AHR) was used to estimate the hydrocarbon volume in the reservoir and test indications of communication across the sands. The analysis indicated that a volume significantly greater than the initial estimated Stock Tank Original Oil-in-Place (STOOIP) is required to match the observed pressures.

Subsequent integration of reservoir performance and geologic data drove the re-evaluation of the seismic interpretation and re-mapping of the field. The new maps buttressed the MBAL volumes estimate and consequently led to the planning of a drillwell to validate the predicted volumes and test the lateral extent of the reservoirs.

The drillwell results confirmed the opportunity identified and validated the volumes estimate from MBAL resulting in a three-fold increase in EUR and potential for additional drilling / resource add in the field. Interpretation of the drillwell RFT pressure data also led to a new understanding of the degree of communication across the sands.

This paper describes the methodology of how early post-production material balance (MBAL) analysis as well as cross-functional collaboration supported volumes growth in the field and tripled recoverable hydrocarbon.
Maximizing Recovery from Peripheral Waterflooding: Case History of Two Water Injectors
Authors: Adegboye Phillip , Okpan Olu
Published: August 2015

Reservoir X01 and X02 are among the biggest reservoirs in AA field located in shallow waters offshore Nigeria. Production started from both reservoirs in 1965. By year 2001, the reservoir pressure in both X01 and X02 had each depleted by about 45% from their initial pressure. Furthermore, the reservoirs were observed to exhibit multiple pressure regions and fluid contacts at dynamic condition resulting from stratigraphic variation and differential production and injection across the reservoirs. Water injection commenced in 2002 into both reservoirs through peripheral waterflooding. It was observed that only the eastern regions of the reservoirs were benefitting from the water injection. By year 2011, reservoir pressure and production from the western region of both reservoirs had depleted significantly; several wells quit production while others had their production rate reduced. Utilizing historical pressure data, production data and other reservoir information, dynamic simulation was constructed to assess the impact of drilling two water injectors, Inj-03i and Inj-05i, in the western areas of reservoirs X01 and X02 respectively. The injectors were needed to provide pressure support as well as to improve sweep efficiency.

In October 2011, Inj-03i and Inj-05i commenced water injection into the western region of X01 and X02 reservoirs respectively. By February 2013, reservoir pressure in the western area of X01 reservoir had risen to 1700 psi, from its pre-water injection value of 1000 psi. Similarly in the western area of X02 pressure increase of 300 was observed post water injection in Inj-05i. Three wells that had earlier quit production in X01 reservoir were restored back to production while two shut-in wells in X02 reservoir were also restored to production. A total incremental production of 5,500 BOPD was attributed to the improved performance in the two reservoirs as a result of the drilling of the two water injectors. Recent flowing and static pressure data were valuable in designing production restoration jobs.
Improving Hydraulic Cement Isolation In Subsea Operations. OML 126 Wells (Phase 1&2 FDP) – A Case Study
Authors: Okoli Ugochukwu , Nwagu Chike , Tayo Ajimoko , Hope Okwa
Published: August 2015

The importance of a good cement bond between the casing and the formation cannot be over emphasized, it is a critical component of well architecture for ensuring casing mechanical support, protection from fluid corrosion, and most importantly isolating permeable zones at different pressure regimes to prevent hydraulic communication. The quality and integrity of a cement job can determine how long a well remains stable and productive without requiring repair.

In the phase one Field Development of the OML-126 block, poor quantitative and qualitative cement bonds were observed in the porous sandstone regions. Following the approval for cased hole designs in the phase 2 Field Development in the same block, it became necessary to investigate the problem in order to ensure proper hydraulic isolation, and the required structural back-up to perforate the casings for cased hole completions.

The study of the reviewed wells developed in the same subject field (OML-126), as well as wells from other fields with similar depositional characteristics. These wells were used to investigate if the petrophysical properties of the formation (porosity, permeability, wettability) had its influence on the qualitative placement of cement.

This paper discusses in sequence how progress was made to achieve the required structural support and hydraulic isolation. Firstly, there was a review of the cementing contractor's design procedures, and recommendations to use a standard API practice to check the rheological properties of the drilling fluids prior to pumping in hole. Then use of water and oil swellable packers in shaly formations as a back-up to primary cementing, to help provide the required hydraulic isolation to prevent early gas cusping and water coning into the wellbore, during production. Lastly, the use of special additives like Microbond HT and Micro-Matrix for primary cementing operations. Micro-Matrix, providing the required characteristic to help plug and seal-off hydrophilic pores in sandstone formations, Microbond HT expanding to isolate any channels left as a result of the drilling fluid not being properly displaced, or water wet to effectively place the cement.

These methods all proved effective as the required hydraulic isolation was achieved, which was confirmed by Cement Bond Logs (CBL) prior to completion.