Oil / Gas Wells And Reservoirs Management In A Nut Shell – Pragmatism & Result Orientation

Introduction

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Oil and gas companies are primarily in business to commercialize oil and gas resource which is the most important underlying asset of the business. The ultimate objective of a reservoir engineer and his employer (upstream exploration and production company, E&P) is the maximization of oil and or gas recoveries at the lowest practicable costs (capital expenditure and operating expenses) possible with minimum negative impact on health, safety and environment (HSE). The tool to achieve this is a robust well and reservoir management plan (WRMP) that is meticulously, effectively, efficiently and executed in a timely manner.?

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Well and Reservoir Management & Management Objectives

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What then is well and reservoir management? It is all the activities deliberately executed with the aim of:

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1.???? Ensuring subsurface development, operational activities and costs are optimal (i.e. sub surface development/ operational actions and costs are technically robust, controllable, relevant, necessary, a balanced compromise/ tradeoff between competing needs, cost effective, value assured and sufficiently risk mitigated)

2.???? Maximizing the effective and efficient use of reservoir energy (energy conservation) to ensure ultimate recovery maximization at the lowest practicable costs possible with minimum negative impact on HSE. In other words, everything practically possible will be done to avoid dissipation of reservoir energy at the lowest practicable costs possible without compromising HSE with the aim of ensuring reservoir energy is sufficiently available to maximize recovery within the unconstrained production life of the asset (wells and reservoirs)

3.???? Creating and giving preference to flow for the more valuable fluids (oil and or gas)

4.???? Prolonging the electro and hydro mechanical life of the wells at the lowest practicable costs possible without compromising HSE. In other words, ensuring the collective and individual functionalities, operability, reliability, safety and unconstrained lifelong availability of the well components/ jewelries whether they are down hole or on the surface, including but not limited to flow control, safe passage of reservoir fluid from reservoir to process facilities etc.

5.???? Maintaining reliable communication with the wells and reservoirs and exercising control and or influence over the performance of the wells/ reservoirs throughout the unconstrained technical life of the wells/ reservoirs

6.???? Protecting the process facility from the vagaries of the well effluents/ flowing stream, well flow behavior, temperature and pressure dynamics

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Well & Reservoir Management Planning & Execution

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Well and reservoir management is both proactive and reactive and commences long before well(s) is/ are drilled and facilities are constructed to receive, process and treat well streams.? The moment a consideration is given to the possible development of a field (collections of reservoirs within a defined oil block or concession), two parallel but complementary actions that feeds off each other until an optimum compromise is reached needs to be executed namely:

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1.???? Preparation of a field development plan (FDP)

2.???? Preparation of a well and reservoir management plan (WRMP)

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At times the WRMP is subsumed inside FDP before the execution/ implementation of the FDP but may be separated afterwards for operational effectiveness and periodic update reasons. Even when separated afterwards, the complementarity of the FDP and WRMP remains in place as the WRMP is intended to give effect to the aspirations/ objectives of the field development plan in terms of ultimate oil / gas recovery optimization, development and operating costs optimization as well as HSE objectives etc.

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The WRMP during the FDP phase is value assurance (VAR) driven or preparatory in nature (i.e. proactive) as there is no well already drilled or facility already built. The post first oil well and reservoir management phase (i.e. during the operating phase of the well/ reservoir) is both proactive and reactive. For both phase (pre and post FDP), the WRMP will typically include some or all following considerations, needs assessments and preliminary designs of wells and facilities but may not be limited to them:

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1.???? Well and reservoir data acquisition, data surveillance and data management needs (both downhole, surface and subsea in offshore environment): This includes both rock and fluid parameters as well as pressure and temperature data. Some data collection are one-off (non routine) especially during drilling, completion and testing of the well while other are routine and will require continuous collection and analysis throughout the life of the well/ reservoir.

a.???? Examples of data and derivable information therein required during the drilling and completion (FDP execution phase) includes rock and reservoir fluid flow properties, phase behavior of reservoir fluids, elasto-mechanical properties of reservoir rock fluid system, fluid contacts, net pay intervals, aquifer presence, ?size and transmissibility, gas cap presence, size and transmissibility, reservoir boundaries, sand and hydraulic continuities, reservoir pressures and temperature, presence of Sulphur, paraffin, CO2 etc.

b.???? Example of data and derivable information therein required post FDP execution and first oil (operations phase) includes oil, water, gas, sand, CO2, hydrogen sulphide and other acidic gases production, production GOR, water oil ratio, gas liquid ratio, water injection, gas injection, bottom hole, well head and surface pressures and temperatures, production separator operating pressures, static bottom hole pressure, surface fluid sampling for fluid properties determination (e.g. API gravity, gas gravity, salinity, gas composition etc.) and water cut measurements.

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2.???? Reservoir energy management needs:

a.???? Examples of data and derivable information required during the drilling and completion (FDP execution) phase includes In-situ reservoir energy data (aquifer presence, size & transmissibility, gas cap presence, size and transmissibility, rock and fluid compressibilities etc.) are collected and analyzed, reservoir energy gap assessment ?and evaluation of potential supplementary external energy (water and or gas injection) to augment in-situ reservoir energy

b.???? Example of data and derivable information required post FDP execution and first oil (operations phase) includes static bottom hole pressure, proportion of free gas in produced gas, draw down amounts and conditions, critical draw down for water or gas coning, fluid injection and offtake rates, reservoir voidage replacement ratios, injected fluid channeling assessments, fluid injection modes (matrix of fracture), reservoir hydrodynamic continuity between injection wells and producer wells etc.

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3.???? Well deliverability needs:

a.???? Examples of data and derivable information required during the drilling and completion (FDP execution) phase includes data on determinants of well productivity such as wellbore size, completion tubing size, perforation interval, perforation shot density & depth of penetration, sand control method, intrinsic flow properties of reservoir rock-fluid system, presence or absence of formation fractures, reservoir boundaries and heterogeneities, saturation conditions of the reservoir, initial reservoir pressure and temperature, ?PVT properties of the reservoir fluids, presences and nearness of fluid contacts to perforations, nearby producer or injector well interference, presence, size and transmissibility of aquifer or gas cap etc. are collected and analyzed to determine optimum choices to maximize well productivity index. Assessment of external inside well bore lift support needs such as electrical submersible pump (ESP), gas lift etc. may also be done as well as formation stimulation needs (formation damage) assessment

b.???? Example of data and derivable information required post FDP execution and first oil (operations phase) includes production test data (fluids production rates, flowing pressures and temperatures, water cut, gas oil ratios, salinity, acidity, produced fluid properties such as API and gas gravities, etc.), static bottom hole pressure data, vertical lift performance (VLP) and inflow performance relation (IPR), well productivity indices, gas /water coning, production logging data (for present fluid contacts determination and channeling diagnosis, fluid source investigation etc.), aquifer encroachment, reservoir voidage replacement ratios, development of secondary gas cap, water oil ratios, gas oil ratios, gas liquid ratios etc. Data are analyzed and tracked to monitor evolution of well deliverability, inside well bore and flow line pressure lift performance, production gas oil ratio and water cut evolution etc.

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4.???? Well & flow line flow assurance needs

a.???? Examples of data and derivable information required during the drilling and completion (FDP execution) phase includes data on paraffin and waxing tendency, fluid flow properties, formation strength and grain size distribution, sand control completion, minimum production rates for fines mobilization and transportation based on grain size/ size distribution and sizes of tubing and flow line, pressure drops in well bore and flow line, well head and flow line pressures and temperatures, production separator operating pressure requirement and minimum pressure drop across choke, minimum flow rate, pressure and temperature requirement for mitigation of formation of gas hydrates, flow line preservation plan (offshore environment) etc.

b.???? Example of data and derivable information required post FDP execution and first oil (operations phase) includes fluids production rates, sanding rates & grain size distribution of produced sand, flow regime/ stability, temperature and pressure parameters at bottom hole, well head, flow line and surface, pressure drops in well bore and flow line, production separator operating pressure, pressure drop across chokes, flow line preservation data for shut in and reopening etc.

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5.???? Potential well and reservoir constraints

a.???? Examples of data and derivable information required during the drilling and completion (FDP execution phase) includes data on well tubular, sand control screen and well head pressure ratings, erosional velocity ratings, maximum/ critical draw down for water coning, gas coning and fines mobilization, static and dynamic stress/ strain related to reservoir pressure depletion and pressure draw down, minimum fluids flow rates for fines transportation in well bore, pressure margin between initial reservoir pressure and bubble point pressure (no free gas flow into well bore), reservoir pressure support (natural aquifer, gas cap or injected water or gas) and corresponding maximum off take rates, relative end point relative mobility ratio of injected and displaced fluids, injected fluids voidage replacement ratio target, integrated well and reservoir optimum operating envelop etc.

b.???? Example of data and derivable information required post FDP execution and first oil (operations phase) includes flowing bottom hole, well head and flow line pressures and temperatures, flow rates and velocities of produced fluids, pressure draw downs, reservoir pressure depletion, formation static/ dynamic strain and total strain, water coning, gas coning and fines mobilization evaluations , fines production rates and grain size distribution of produced fines, reservoir pressure, aquifer recharge rates, gas and water injection rates, voidage replacement ratio etc.

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6.???? Potential facility constraints

a.???? Examples of data and derivable information required prior to and during the drilling and completion (FDP execution phase) includes data on process and treatment capacities for oil, water, gas and gross liquid, maximum operating pressures and temperature of flow lines, minimum operating temperatures of flow lines, maximum permissible flow velocity in flow lines, maximum permissible sanding rate through flow lines etc. At this phase these data constitutes the basis of design/ design boundaries.

b.???? Example of data and derivable information required post FDP execution and first oil (operations phase) includes available process and treatment capacities for oil, water, gas and gross liquid, operating pressures and temperatures of flow lines, de-rated operating pressures and temperatures of flow lines, operating temperatures of flow lines, flow velocity in flow lines, de-rated maximum permissible flow velocity in flow lines, sanding rate through flow lines, de-rated maximum permissible sanding rate through flow lines etc. At this phase these data constitutes operational constraints on use of production facilities.

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7.???? Potential regulatory constraints

a.???? Examples of data and derivable information which are either strictly regulated and or regulatory advisory in nature during the drilling and completion (FDP execution) phase and post FDP execution/first oil (operations phase) includes technical allowable rate (place a cap on the maximum off take of each well from a specific reservoir), current reservoir pressure relative to initial reservoir pressure, maximum allowable reservoir pressure depletion, maximum allowable sanding rate, offtake vs injection rates targets, voidage replacement ratio targets. Requirements that are regulatory are enforceable and violations could attract regulatory sanctions

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More often than not, well and reservoir management (WRM) is not a straight jacket ticking of the checklist of implemented considerations, needs and constraints above. There are always competing and at times mutually and or near mutually exclusive considerations, objectives and needs. Consequently, an integrated system (consisting of the reservoirs, wells, facilities, HSE, regulations, external/ exogenous environment etc.) Optimum Operating Envelope (OOE) has to be developed to reconcile competing needs and constraints. This OOE is also an integral part of the WRMP and makes a delicate balance of competing needs by defining operating boundaries and boundary parameters within which the wells/ reservoirs will be operated to deliver optimum value as anticipated in the WRM objectives.

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Example: for an offshore oil / gas well in a turbidite reservoir with down hole sand control already in place, there is still need to prevent fines production by limiting draw down to a level below the critical draw down for fines mobilization. This need is complicated and challenged by other needs/ constraints such as minimum economical flow rate, minimum flow rate required to transport fines from wellbore to well head into the subsea flow line, the minimum flow rate required to transport fines from subsea flow line to topside facility, maximum acceptable sanding rate for facility integrity assurance, the maximum allowed offtake rate of the well and reservoir imposed by the regulatory authority etc. It is the duty of the well and reservoir management specialist to navigate this maze and still deliver the WRM objectives.

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It should also be noted that the WRMP needs to be updated throughout the operative life of each well/ reservoir to account for the changing needs of the well/ reservoir vis a vis its behavioral changes e.g. the WRM considerations before and after injected fluid (water or gas) break through could be substantially different. Water and gas break through could impose facility process capacity limitations and change the lift pressure performance of the well for the better or for worse. Water breakthrough also weakens the formation and diminishes its unconfined compressive strength (UCS) thereby reducing the critical drawn down threshold for fines mobilization. Water breakthrough also improves the capacity of the well stream to transport solids (fines) due to its higher propensity to entrain solids compared to oil and gas (density differential effects)

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Figure 1 below is a sample well and reservoir management work flow.

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Over all, the reservoir management process is an inquire-and-act binary cycles of operation

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Well and reservoir management and intervention actions may range from simple “no incremental cost” operational actions to actions involving significant operating cost. A few is listed herein for illustration

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?????? I.????????? Preparation, scheduling, monitoring and control of the implementation of routine and none routine well tests e.g. routine well testing for the purpose of back allocation and current performance assessment, investigative well testing such as reservoir limit test, well interference testing,? multi rate testing, regulatory imposed testing such as maximum efficient rate test etc.

???? II.????????? Production parameters monitoring, collection, processing, storage and integration into well and reservoir management data bases

??? III.????????? Development and implementation of algorithms for production and injection back allocation of oil, water and gas

?? IV.????????? Quality check and control of production and injection back allocation of oil, water and gas

???? V.????????? Well production performance diagnostics e.g.

a.???? Water and gas coning,

b.???? Changes in production gas oil ratio (GOR), water cut, water oil ratio (WOR)

c.????? Evolution of productivity index and formation damage

d.???? Evolution of static bottom hole pressure (SBHP)

e.???? Evolution of oil API gravity, gas gravity, salinity, hydrogen sulphide

f.?????? Arrivals of water and or gas fronts in watered out or gases out layers in wells etc.

g.???? Source of free gas in wellbore (draw down induced or gas cap gas)

h.???? Tracer campaigns and finger printing

i.?????? Production logging

?? VI.????????? Monitoring/ tracking, assessment and control of critical parameters and constraints e.g.

a.???? Technical allowable rate (maximum off take of each well from a specific reservoir prescribed by regulation),

b.???? Current reservoir pressure relative to initial reservoir pressure,

c.????? Maximum allowable reservoir pressure depletion,

d.???? Maximum allowable sanding rate,

e.???? Offtake vs injection rates targets,

f.?????? Voidage replacement ratio targets

g.???? Flowing bottom hole, well head and flow line pressures and temperatures,

h.???? Flow rates and velocities of produced fluids vs erosional velocity limits

i.?????? Pressure drawdowns with respect to water coning, gas coning, fines mobilization, dynamic strain etc,

j.?????? Reservoir pressure depletion target

k.????? Formation static/ dynamic strain and total strain

l.?????? Fines mobilization evaluations,

m.?? Fines production rates and grain size distribution of produced fines,

n.???? Static reservoir pressure,

o.???? Aquifer recharge rates

p.???? Gas and water injection rates

q.???? Voidage replacement ratio

r.????? Available process and treatment capacities for oil, water, gas and gross liquid

s.????? Operating pressures and temperatures of flow lines,

t.????? De-rated operating pressures and temperatures of flow lines,

u.???? De-rated maximum permissible flow velocity in flow lines,

v.????? De-rated maximum permissible sanding rate through flow lines etc.

?VII.????????? Planning and execution of well and reservoir performance recovery operations

a.???? Well stimulation

b.???? Water shut off operations

c.????? Gas shut off operations

d.???? Perforations wash off

e.???? Formation sand consolidation operations

f.?????? Well workover

g.???? Production interval re-perforation

h.???? Restoration of external pressure support (water or gas injection)

VIII.????????? Development of well are reservoir models for production forecasting, recoverable reserve forecasting, remaining reserve forecasting, production strategy and scenario planning, assessment of impacts (well and reservoir response) of reservoir management actions prior to execution, prediction of fluid contacts movements, identification of by passed oil and infill drilling opportunities, testing impact of well location on recovery and optimization of well locations etc.

?? IX.????????? Etc.

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Well & Reservoir Data Quality Management

?So far, a lot of effort has been placed on data needs for an obvious reason – wells and reservoirs management is both data intensive and data driven. Data is the only means of communication with the reservoir–well system and the quality of that communication is critical to success. Wells and reservoir models are quite unhelpful as management tools when such data is heavily compromised, creating unmanageable range of uncertainties and unreliable model outcomes.

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There is therefore needs for quality assurance and quality control across the data acquisition value chain

???????? i.????????? Equipments/ tools for data collection

?????? ii.????????? Processes for data collection, handling, storage, transmittal & processing

????? iii.????????? Human inputs, human machine interfaces and interactions in relation to data collection, handling, storage, transmittal & processing

????? iv.????????? Technical assessment of data integrity

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Figure 2 below is a sample work flow foe WRM data quality assurance and quality control.

?The Author:

Engr. Godwin Onwubolu FNSE, FCAI is practicing petroleum engineer with over 12 years experience in well and reservoir management in deep offshore environment

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