bluuebunny/crossref_metadata_2025_split huggingface dataset:
Practical Application of the IPSM in Resolving Gas Availability Challenges and Overall System Optimisation to Maximise Production
Authors: Thomas Ayoola Olakunle , Tohira Shakioye , Edidiong Taiger , Linus Nwoke 
Published: August 2012

Abstract
With global energy demands on a steady increase, it is important to ensure hydrocarbon production optimisation and sustainability while minimising production process impact on the environment. As a result, technologies and processes that improve response to production challenges and guarantee optimisation and sustainability of production and products utilisation, especially associated gas, have become more relevant in the oil and gas industry.
The Integrated Production System Modelling (IPSM) tool is a means of simulating actual production systems and assessing their responses to changing production scenarios, challenges and the impact of various solutions on production systems before effecting the changes in the field. IPSM was used to assess the options of ensuring gas availability to meet the minimum turndown ratio of the associated gas gathering (AGG) low pressure compressor and ensure optimal oil production from a field in the Niger delta of Nigeria. Declining gas production from the producing oil wells in the field poses the challenge of keeping gas production above the minimum required turndown ratio for the compressor to run. A multi-disciplinary review and production system optimisation identified the options of re-routing either of two producing oil wells with significant gas production rates from a nearby field to the production facility of the field of interest to ensure the minimum required gas is always available. The impact of re-routing each of the proposed wells on the overall production system efficiency was analysed using IPSM with a view to optimising oil and gas production without compromising recovery from the wells in the field of interest.
The results from the analysis indicate that IPSM is a robust tool for analysing the various options and optimising the required solution. The impact of the different options on overall system health was quantified and greatly enhanced the business decision making process with overall benefit of provision of required LP gas to run Field Y compressor, safeguarding the invested fund of building the AGG plant in addition to a projected 5MMscf/d sales gas.
Acid Stimulation by Bull-heading and Back-production: The Bonga Experience
Authors: Okoh Ehimhen , Olatunbosun Olugbenga , Ogunsina Oluseye , Uche Enor , Eta Kingsley , Oduola Lukman , Beldongar Maye 
Published: August 2012

Abstract
Bonga producer (Well-X) became severely impaired during a series of interventions (to address SCSSV failure), with oil potential dropping from 18 to 3 kbod. The Well and Reservoir Management team believed the initial impairment was most likely caused by fines migration and secondly by fluid (MEG and brine) losses to the formation during interventions. A two-fold treatment was recommended –solvent (surfactant) and half stre gth mud acid to target the two impairment mechanisms. Considering the relatively low productivity and remaining reserves, the downside risk was low from a subsurface perspective. The major concerns were related to HSSE and integrity risks pertaining to unspent FPSO. Lessons learnt similar jobs by other acid flow-back to the Bonga from successful executions of Operators enabled the Bonga team to demonstrate the necessary risk management and purs e the concept towards execution.
To minimize cost, the recommended deployment method was by bull-heading the treatment from the Field Support Vessel, via a flexible hose connected to the tree, and subsequently to back produce the well fluids to the FPSO with injection of Soda Ash to neutralize any unspent acid on the topsides. The key challenges that needed to be addressed were: Identifying an appropriate stimulation recipe, Ensuring adequate pump rate of stimulation fluid given limited pressure rating of the flexible hose, Managing flowback of unspent acid to topsides, Metallurgy compatibility with the stimulation fluid, ydrate risk and Production of H2S from chemical reaction. Full integration of the various functional aspects was essential for effective planning and execution.
The Well-X stimulation led to an increase in production frrom 3 to 22 kkbod, with PI improving from 1.4 to 86 bpd/psi; a PIF of 60. Industry experience shows that gaains from mud acid stimulation to attack fines can typically be sustained for up to 12 months, while the partial gain from surfactant to remove MEG/brine impairment is expected to be sustained permanently. TThhis success paves the way for further acid stimulation in the Bonga field where fines migration is typical among producers, and provides opportunities for production acceleration in the field and other upcoming developments.
Technical Evaluation of Secondary Oil Recovery Methods, A Case Study on one of the Iranian HPHT Carbonate Reservoirs
Authors: Sajjadian S. , Ataabadi V. Mahmoudian , Dalaei M. 
Published: August 2012

Abstract
The reservoir under study is a HPHT (high pressure-high temperature) reservoir with high amount of H2S and asphaltene. It has more than 1 billion of recoverable oil as static geological model estimated but the problem is the only drive mechanism is Solution gas drive and it has no active aquifer so although it had good flow potential but what if it drops lower than bubble point pressure? Dynamic model showed it was to deplete quickly. By using new reservoir management techniques and enhanced oil recovery in order to pressure maintenance one can recover a lot more oil.
The scope of this project was to evaluate in terms of impact of surface facilities, reserves and recovery factor of using gas injection and then different fluid composition for this field's gas injection
Water Injection Rich gas corresponding to the associated separator gas to be re-injected to reservoir Lean gas corresponding to the associated separator gas to be re-injected to reservoir after condensate removal
There are 40 wells in this fields and this was possible to change function of production well to injector if needed.
A team of Reservoir, Production, Process, Facility and Environmental engineers worked on the possibility of Secondary recovery by injection and its challenges.
Simulation models were run for different scenarios and realizations and the best composition of injection fluid was selected by considering reservoir rock and fluid data and different injecting fluid composition and different injection pressure.
After comprehensive study and technical evaluation it was found that. Miscible gas injection was the best scenario allowing 0.66 BSTB Recovery increase and 9 years longer plateau compared to Natural depletion.
Field Development: Reservoir Development Strategy, A 3-D Modeling Approach
Authors: Agina Henry L. , Ahunanya Dike O. , Ekebafe A. O. 
Published: August 2012

Abstract
This paper presents a proposed development plan of an oil onshore reservoir replica. The reservoir comprises sandstones with moderately high porosity/permeability distribution. Recoverable oil from the reservoir is 527 million barrels through primary energy, found to be gravity drainage and an underlying aquifer. The reservoir sits at 7840ft from below sea level with area of 2400acres.
The structure of the reservoir showed three (3) major faults compartmentalizing the reservoir into four (4) fluid-in-place regions, two (2) of such accounted for 70% of the water production. Smart wells were drilled to control water production from such zones, wherein Inflow control valves (ICVs) were designed and optimized for selective shutoff or delay of water production, in effect increasing recovery. Horizontal and highly deviated wells' trajectory and displacement was also considered because of potential non-sealing faults that divided the reservoir into layers or compartments.
Optimization of proposed development plan was done with objective function of maximizing ultimate recovery (UR) via fluid production till reservoir abandonment. This could be used proxy optimization models for part or group of reservoirs in a big field.
This paper reiterates the importance/role of reservoir modeling and simulation with and necessary sensitivities that will assure optimized full field reservoir development.
Interference Testing in Anisotropic Composite Reservoirs with Leaky Faults – A 3D Semi-analytical Approach
Authors: Ezulike D. O , Igbokoyi A. O 
Published: August 2012

Abstract
This paper illustrates how horizontal well interference tests in composite reservoirs can be analyzed using Tiab's direct synthesis (TDS) and curve matching techniques; providing insight into the three dimensioned nature of associated fluid flow.
Resetroir heterogeneity is the reality and has been studied under various contexts including composite systems, multilayered systems, dual porosity systems, dual permeability systems, triple porosity systems; each with its corresponding flow anisotropy. A composite resen oir is one with multiple compartments; each having distinct rock and fluid properties separated by geologic discontinuities. Importantly, this reservoir system is encountered often in fields due to the geologic interplay between depositional and tectonic forces.
For the first time using transform methods, a general customizable three dimensional point source semi-analytical solution for the drawdown response in composite clastic systems separated by a leaky fault is developed. This solution is then converted to line source for horizontal well observers by integrating along the producing well length while treating the leaky fault as a thin finite conductivity fracture separating two reservoirs with different rock properties. An arbitrary well orientation to principal permeability direction is adopted to obtain a general solution in an anisotropic system and this semi-analytical solution is achieved using a simple computer program which can generate type curves in a computationally cheap and effective manner.
Sensitivity analysis conducted on generated interference responses with respect to areal permeability anisotropy, well position, reservoir dimensions, dimensionless fault conductivity and mobility ratios in composite clastic reservoir systems reveals that the response is a convoluted function of resetroir properties from both compartments and the separating semi-permeable medium.
It is observed that the intersection time between the long-time approximation of both observer pressure drawdown and observer pressure derivative is unique - from which producer hydraulic diffushdty could be obtained. Tiab direct synthesis (TDS) of resetroir parameters from the resulting equation is examined. From resulting type curves, it is observed that there exists a limiting fault conductivity, compartment-permeability contrast and well-fault distance among other reservoir parameters that could register on the drawdown response signature.
The result of this work is attractive where sand juxtapositions separated by leaky faults in the reservoir is suspected to allow flow from adjacent fields, especially if an existing well in the other compartment can be used as an observer.
Improving Recovery from Oil Rim Reservoirs by Simultaneous Gas and Water Injection
Authors: Onyeukwu I. H. , Peacock A. , Matemilola S. A. , Igiehon O. 
Published: August 2012

Abstract
This paper presents the results of the study that was initiated to investigate the incremental benefit of gas and/or water injection in the production of oil rim reservoirs. Due to the nature of the project, emphasis had been on maximizing oil recovery. Consequently, only the incremental oil recovery was used to screen development concepts with a view to optimizing the overall economic value of the concept.
This paper includes reservoir simulation on oil rim development with gas and/or water injection with sensitivities on: 1) Permeability anisotropy, Kv/kh 2)GOR relaxation policy 3) Aquifer strength 4) Oil Column Thickness (Ho) 5) Well placement.
Results of this study suggest that simultaneous gas and water injection (voidage replacement maintained) could increase recovery factors by upto 15% of STOIIP.
Development of a Model to Calculate Rig Power Requirements for Geothermal Applications
Authors: Bello O , Teodoriu C. 
Published: August 2012

Abstract
Many methods have been used to reduce power consumption of rig systems in drilling, completion and workover applications. However, the effects of various parameters on rig system power consumption have not been previously investigated for geothermal operations. Study of such issues is of significant importance because it enables estimation of possible range of parameters where rig system deployment for geothermal drilling operations can be economically viable.
The purpose of this study is to create a method which can help engineers choose a combination of parameters that minimize power consumptions. In this work, a computational approach is presented in quantifying rig system energy consumption associated with geothermal drilling operations. The corresponding analytical approach in quantifying energy consumption of geothermal rig system is shown. The paper is geared towards achieving effective and efficient geothermal drilling processes by researching into trends in energy losses.
The results obtained show the feasibility of the applied procedure and provide a methodology for determining optimal conditions for geothermal drilling operation, which can substantially improve rig power efficiency from their current states. The parametric study also demonstrates that the decision of the geothermal drilling rig operating policy at the design stage can have a significant effect on the power savings and costs.
Deepwater Drilling Operations Challenges of Exploration Well in Alpha Block, Gulf of Guinea: Lessons Learned
Authors: Onugbolu Olisaka , Rodrigues Carlos , Maueler Roberto , Lewis David Wayne , Loyola Charles 
Published: August 2012

Abstract
Deepwater environment pose several challenges and constraints on well drilling operations. These challenges include but are not limited to harsh and hostile weather conditions, distance from shore, water depth, personnel safety and piracy in some cases. All these can be successfully managed and operational excellence achieved through innovative approaches.
The aforementioned challenges, if not recognized and adequately addressed especially during the well planning phase, will ultimately manifest as unscheduled downtime, high-risk exposure, low operational performance and above all, increase in overall well cost. Petrobras and her partners recognized these challenges during the planning phase of a recent exploration well and put measures to optimize the operational efficiency of the well.
The exploration well is located in deepwater ALPHA block offshore outer continental shelf waters of Nigeria; western flank of the Niger Delta. The acreage spans 853.5 km2. The water depth range from 1600m to 1800m and an approximate round-trip sailing time of 60hrs (about 350 nautical miles) from the logistics base. Round-trip flight time of 1 hour (about 80km) from the nearest airport. Thus, the environment is considered remote with high level of logistics challenges.
This paper presents some of the innovative approaches employed in managing the challenges which led to the positive results achieved. It is imperative to note that our intent is to share our experiences and lessons learned in this well operation with the industry so that drilling operational process can be improved and well cost reduced significantly.
Relative Rock Strength Determination from Well Logs - Comparison of Deepwater Fields, Offshore Nigeria.
Authors: Jenakumo Timipere , Adoghe Leo-Andrew , Aniekwe Osita , Nwosu Chike 
Published: August 2012

Abstract
Elastic constants (Poisson ratio, Young's and Bulk Moduli) and acoustic velocities are often used to specify the strength of rock materials. An understanding of reservoir rock strength and geomechanical issues related to drilling and producing from unconsolidated formations are essential for well completion and injection design as well as production performance and optimization of recovery.
Typically, laboratory tests such as unconfined compressive strength, triaxial strength test from cores provide stress and strain parameters from which the elastic constants are derived, and rock strength is determin d. In the absence of these laboratory tests, this study has used well logs (density, compressional and shear wave velocity) to derive the dynamic rock mechanical properties and assessed the relative rock mechanical strength for four select Nigerian deepwater fields.
This work investigates the possible impact of formation strength of four deepwater fields with respect to causes of drilling, completion and injectivity issues. Water injector wells in Field B1 are seen to be quite successful, whereas this is not the case in field A1.
The studyresults provide some insight into the relative degree of consolidation between these fields. Comments on the completion practices and injection into similar rocks in these fields will be based on the determined relative rock strength.
Effective and Innovative Approach to Integrating Static and Dynamic data: A key to Volumes Optimization in Erha Field
Authors: Mudi K. C. , Idih R. E. , Sarumi O. S. , Etta C. O. , Ejayeriese A. O. , Nwogbo N. C. , Oke A. A. 
Published: August 2012

Abstract
Erha field is a stacked deepwater slope confined channel complex system. Vertical and lateral communication between channel sets and individual channel sands is hampered by a series of cross cutting faults and a complex vertical channel stacking pattern. The principal depletion mechanism in Erha is gas-cap drive with support from both gas and water injection to effect simultaneous closure of the GOC and the OWC around producer completions. Erha field currently produces about 85 kBOPD & 340 Mscfd gas with a STOOIP of 1.46 GBO and a 34% recovery factor. Year End 2010 recovery is 220 MBO.
A key challenge for interpretation and surveillance is the identification of flow barriers/baffles. The complex geology and degree of compartmentalization make it difficult to define reservoir connectivity between the channel complex sets. Gas channeling through high permeability pathways is a major challenge in Erha with 6 wells shut in due to high GOR and the remaining 9 producers showing elevated GORs. A key opportunity therefore is the development of a reservoir management plan that accounts for these complexities and performance.
The Erha subsurface team, including representatives from geology and reservoir engineering, has identified potential baffles and barriers by integrating static and dynamic reservoir data. As a result, a revised gas injection strategy was initiated, significantly mitigating gas channeling and thereby improving oil rates, prolonging well lives and maximizing the asset value. Additionally, the improved description of reservoir connectivity underpinned the development of new geologic and simulation models that will be used in the determination of potential bypassed oil and infill drill wells/completion strategies.
HSE Culture as a Panacea to redefining HSE Excellence and Sustaining HSE Best practices
Authors: Bada A. J. , Ugbebor J. 
Published: August 2012

Abstract
The paper is a follow-up in achieving HSE excellence through institutionalizing HSE. Several tools are used in achieving HSE excellence but HSE culture has been used in this paper as a forerunner to a holistic HSE practice that is sustainable. It explains the need to redefine HSE excellence after ensuring that HSE culture has been engrained in all facets of the organization to the extent that HSE activities are performed as part of normal daily routines. The emphasis in this paper is based on experience which shows that HSE is being seen in the light of occupational safety than for process safety. Varied illustrations of disasters were highlighted showing the importance of redefining HSE excellence through HSE culture. Many organizations despite their HSE Culture programs still experience sudden HSE backwardness. Barriers to positive HSE culture was described and how to develop positive HSE culture in an organization. Pro-active safety in preventing skill-based errors, mistakes and violations to achieving HSE excellence was also mentioned. Many organizations have failed to realize that moving past the traditional HSE culture to redefining HSE excellence is the only way to achieving results. Achieving institutionalized HSE performance required HSEMS that includes Active leadership, HSE risk Assessment, behavioural change program, Leading and lagging HSE Performance Indicators, empowerment and dialogue. It concludes that good HSE culture is critical to prromoting HSSEEMS implementation, conducive for risk reduction in all organization's activities and, ensures productivity. Practicing HSE excellence moved beyond HSE culture to ensure that HSE performance is a journey and not a destination.
Coal Bed Methane System Modeling – Integrating Reservoir, Wells, and Facilities
Authors: Ori-Jesu E. 
Published: August 2012

Abstract
Coalbed methane (CBM) holds promise of relatively clean, stable natural gas supply in the emerging global energy map. This project summarizes the integrated modeling of a unit of a coalbed methane reservoir-well-surface facilities system. The pro ect demonstrates the resulting reservoir and system response for different well fluid and pressure conditions, for a range of artificial lift parameter and surface facilities constraints. An economic cost model is also linked to the coupled system, which incorporates ranges for gas prices, water handling costs, capital and operating costs and discount rates. The instant capability to examine the possible net present values and internal rates of return for a given production stream of gas and water is also demonstrated. The simultaneous optimization of the reservoir, well, surface and economic models in a single simulation run made possible by proprietary oil industry software enables the observation of the system behaviour instead of just the reservoir as has been mostly done in industry. The reservoir effects on this coupled system are presented to explain important considerations in CBM feasibility considerations. The resulting model is scalable to deal with larger fields and well patterns.