Al-Garadi, Karem (King Fahd University of Petroleum and Minerals) | Aldughaither, Abdulaziz (King Fahd University of Petroleum and Minerals) | Ba alawi, Mustafa (King Fahd University of Petroleum and Minerals) | Al-Hashim, Hasan (King Fahd University of Petroleum and Minerals) | Sibaweihi, Najmudeen (King Fahd University of Petroleum and Minerals) | Said, Mohamed (King Fahd University of Petroleum and Minerals)
Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells.
In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity.
The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.
Babajide, Ale (Covenant Univesity) | Adebowale, Oladepo (Covenant Univesity) | Adesina, Fadairo (Covenant Univesity) | Churchill, Ako (Covenant Univesity) | Ifechukwu, Micheals (Igbenedion University)
The primary cause of wellbore instability is the interaction of water based mud with shales which usually involves the movement of water and ions into or out of shale thereby causing alterations in mechanical property of the shale resulting in dispersion of shale particles into the mud. This work involves experiments to analyze the effects of chemical osmosis, diffusive flow prior to shale hydration and inhibition, determination of the effects of salt addition on pH and density of mud and also determination of the effect of Temperature and pressure other than just temperature on dispersion of shale cuttings into water based mud.
Ogienagbon, Adijat (Petroleum Engineering Department, University of Benin) | Taiwo, Oluwaseun Ayodele (Petroleum Engineering Department, University of Benin) | Mamudu, Abbas (Petroleum Engineering Department, University of Benin) | Olafuyi, Olalekan (Petroleum Engineering Department, University of Benin)
The global oil price as well as Nigeria’s current reserve is on a continuous alarming decline. With the increasing finding cost of new wells and demand for energy, improving oil recovery from existing wells becomes highly pertinent. Generally, waterflooding leaves approximately two thirds of the OIIP as un-swept or residual oil resulting to a low recovery factor. The improvement of recovery factor is one of the identified five Research & Development (R&D) grand challenges or upstream business needs highlighted by the SPE R & D committee. Enhanced Oil recovery (EOR) methods provide an avenue to Petroleum engineers to unravel this challenge. In lieu of this, we investigated the feasibility of improving recovery with polymer flooding technique in the Niger Delta region of the Sub-Sahara Africa. A sequence of brine saturation, oil saturation, water flooding and polymer flooding was carried out on four different cores (core A, B, T & R). Core A & B are ROBU cores (specially manufactured synthetic cores), T is Bentheimer core and while R is a reservoir rock core sample from a shallow central Onshore Niger Delta reservoir.
The results show comparative responsiveness of oil recovery to polymer flooding by the various core samples. Core samples T & R are good candidates for polymer flooding having produced 21.28% & 13.33% after polymer flooding. Model Bentheimer rock sample (T) which has close petro-physical properties to that of the case studied reservoir has the highest displacement efficiency of 52.63%. The core flood analysis demonstrated that polymer flooding could improve oil recovery within the Central Onshore reservoir of the Niger Delta.
Hydrocarbon accumulations more often than not straddle two or more license areas or concessions and sometimes, international boundaries. Unitisation is a process whereby petroleum reservoirs (fields) straddling concession boundaries are developed and exploited as a unit using a single operator (the Unit Operator) and common production facilities under a signed agreement (Unitisation Agreement), by the holders of the respective concessions. The objective is to maximise economic recovery of producible hydrocarbon. In Nigeria, the enabling law that gives legal backing for unitisation is the Petroleum (Drilling & Production) Regulation 1969, Section 47, as amended and the 2008 Unitization Guidelines by the
One of the major milestones in the unitization process is the signing of the unitization and unit operating agreement (UUOA). The UUOA specifies how the straddle field is to be operated and defines tract participation (the equity interest, assigned to each Concession in the Unit). As at today, over seventy (70) straddle fields have been identified in Nigeria but not up to five (5) UUOA agreements have been executed. Issues ranging from correct interpretation of Regulation 47,recognizing unitization of straddling and non-straddling reservoirs, to single and combined provisional tract participation (PTP) for oil and gas, economic consideration & contractual disputes, fiscal terms, Redetermination, Reference dates, appointment of unit operator, funding, divestment, political and personal interest etcetera, have made unitization of straddle fields elusive for many years thereby locking down billions of barrels of reserves. This undoubtedly, is not in the national Interest, especially when the Country is striving to increase the Nation's reserves base from the current 36.24 barrels of oil to about 40 billion barrels and the daily production output of 2.5 million bopd to 4.0 Million bopd by year 2020.
This paper therefore examines the synopsis of unitisation and joint development of straddle fields in Nigeria, the concerns and pitfalls arising thereof. The evaluation of some selected cases is also made to ascertain the effect of delay from Government objectives of reserves addition and production along with suggestions for future policy formulations.
Marfo, S.A. (World Bank African Centre of Excellence in Oilfield Chemicals Research, IPS, Uniport) | Appah, D. (Department of Petroleum and Gas Engineering, Uniport) | Joel, O.F. (Centre for Petroleum Research and Training, IPS, Uniport) | Ofori-Sarpong, G. (Mineral Engineering, University of Mines and Technology, Tarkwa, Ghana)
Sand consolidation as a sand control method has been applied in the oil industry for nearly eight decades. Chemical sand consolidation has evolved since its first application in the early 1940s. Despite the failures recorded and its limitations in application in some oil and gas wells, this method has recorded some remarkable successes both as a primary and a remedial method of sand control in the petroleum industry. This paper presents the operation constraints in sand consolidation since its first use in the industry, the selection criteria and remedy. It also considers the types of resins which have been used over the years: highlights of sand consolidation methods in high clay content formations and the problem of long shut-in time for sufficient consolidation strength in reservoirs with either relatively low or high bottom-hole treatment temperatures. Moreover, recommendations on the way forward to manage these operational problems are elucidated.
Ndokwu, Chidi (Baker Hughes) | Okowi, Victor (Baker Hughes) | Foekema, Nico (Baker Hughes) | Caudroit, Jerome (Addax Petroleum Development) | Jefford, Leigh (Addax Petroleum Development) | Otevwe, Joseph (Addax Petroleum Development) | Fang, Xiaodong (Addax Petroleum Development) | Idris, Maaji (Addax Petroleum Development)
High-angle or horizontal wells pose many geological challenges that include maintaining well trajectory within a particular horizon in drain sections, detecting stratigraphic positions after passing a discontinuity, and subsurface feature identification. Geo-steering has shown increased value over the years because it uses data from different sources, including borehole imaging, to meet these challenges. Bulk density and gamma ray borehole images can be used to describe the near-wellbore environment, and that description can be analyzed further to explain the near-wellbore structural geology. In this study, structural analysis and zonation of bulk density and gamma ray images were used to detect the fault zone, while a geo-steering application was used to pick the true stratigraphic depth after crossing the fault. Provision of an alternative model to seismic-only interpretations and a better understanding of subsurface structures are the industrial benefits of this study. The Niger delta sedimentary basin of Southern Nigeria is a prograding depositional complex of Cenozoic-aged sand and shales that extends from about longitude 3 - 9 E and latitude 4 30' - 5 20' N. This paper demonstrates the importance of geo-steering, shows the application of geo-steering in a high-angle well drilled in the Niger delta sedimentary basin, and establishes the importance of structural analysis from borehole images in making final geo-steering interpretations. This paper also shows that borehole imaging is an additional and useful source of information in the planning stage of any drilling campaign.
Onikoyi, Abiola S. (Shell Petroleum Development Company) | Nwabueze, Vincent O. (Shell Petroleum Development Company) | Okoro, Felix O. (Shell Petroleum Development Company) | Ajienka, J.A. (University of Port Harcourt)
Several criteria and strategies have been developed to predict sand failures and to select appropriate sand control methods for improved completion designs and to maximise oil production at moderate unit technical cost. The depth criterion, SPADE equation, Rock Mechanic Equations incorporating Brinell Hardness Number and Unconfined Compressive Strength have been used extensively to predict sand production tendencies and to propose completion types. None of these criteria and strategies has explicitly incorporated the depositional environmental factor that defines the origin of these oil-bearing formations. A recent study aimed to correlate depo-belts and depositional environments to actual sand production using historical data of producing wells in the Niger Delta but covered only the Greater Ughelli depo-belt to some depths (SPE-163010). That study indicated a predominance of high sand producers in the channel sands depositional environment of the Greater Ughelli Depobelt. This paper therefore seeks to complete the investigation across all the remaining depo-belts and litho-facies and to share the review outcomes/ findings with the goal of establishing correlation between known rock mechanic principles and models used in sand failure prediction and sand control selection as a total system approach, providing wider solutions to sand control challenges in the oil industry.
With gas production from gas condensate reservoirs, the flowing bottomhole pressure of the production well decreases. When the flowing bottomhole pressure becomes less than the dew point pressure, condensate accumulates near the wellbore area and forms a condensate bank. This results in loss of productivity of both gas and condensate. This becomes more serious in intermediate permeability gas-condensate reservoirs where the condensate bank reduces both the gas permeability and the well productivity.
Several techniques have been used to mitigate this problem. These methods include: gas cycling, drilling horizontal wells, hydraulic fracturing, injection of super critical CO2, use of solvents and the use of wettability alteration chemicals. Gas cycling aims to keep the pressure of the reservoir above the dew point pressure to reduce the condensation phenomena. The limited volumes of gas that can be recycled in the reservoir can hinder the application of this method. In order for an ideal recycle, gas volume injected into the reservoir will be larger than the total gas that can be produced from such a reservoir. Other approaches are drilling horizontal wells and hydraulic fracturing where the pressure drop around the wellbore area is lowered to allow for a longer production time with only single phase gas flow to the wellbore. These approaches are costly as they require drilling rigs. Another technique is the use of solvents which shows good treatment outcomes, but the durability is a questionable issue in these treatments. Moreover, wettability alteration needs to be approached very carefully as to not cause permanent damages to the reservoir. It was reported in many studies the use of fluorinated polymers and surfactants dissolved in alcohol-based solvents for wettability alterations treatments.
Each method has its own advantages and disadvantages, and can be applied under certain conditions. The paper presents all of these methods along with their advantages and disadvantages, besides description of some of their field applications and case studies.
Sand production in oil wells impairs full reservoir production capability, erodes sand face completions, down-hole tubular and surface equipment. The debilitating effects of sand production on surface production equipment are manifested in the plugging of flow lines, production manifolds and separators , leading to significant deferment in production due to downtime of facilities for sand clean out and component repair and replacement.
2000 oil wells in the Niger Delta area have been reviewed to understand the sanding tendencies of the oil well completions and establish the completion strategy and practices that have successfully reduced sand production and its impact. It is observed that over 100 Mbopd oil is locked in as a result of produced sand. A plethora of sand control mechanisms such as Internal Gravel Packs, External Gravel Packs, Stand-Alone Screens, Premium Screens and Sand Consolidation Chemicals have been installed to reduce sand production in oil wells to acceptable rates but several cases of failures have been observed reviewing the past history of the oil wells.
While several operators have developed guidelines to judge when sand control is required and how to operate the oil wells safely, there are still grey areas to be explored to understand the variation of formation consolidation indices from one Depo-Belt to another. The sand production performance of 2000 wells have been reviewed to examine whether the tendency for sanding can be attributed to oil well completion techniques or in-situ formation consolidation or a combination of both. It is also widely believed that formation burial depth can be used as a consolidation parameter to decide whether to include sand control in oil completion design or not.
This paper seeks to share the results of the review of a large population of wells located and completed in different Depo-Belts in the Niger Delta with a view to helping operators streamline their decision-making process to include or not to include sand control systems in their oil wells for efficient production performance at less deferment due to sand production and lower completion and operating cost.