Petroleum Production Engineering

• Petroleum production involves the reservoir and artificial structures.
• The reservoir is a porous medium with unique storage and flow characteristics.
• Artificial structures consist of wells, bottomhole and wellhead assemblies, and surface facilities.
• Production engineering aims to maximize production (or injection) cost-effectively.
• Production engineering technologies are interdependent with formation evaluation, drilling, and reservoir engineering.

Formation Evaluation

• Modern formation evaluation creates a reservoir description using 3-D seismic, log correlation, and well testing.
• This description identifies geological flow units and characterizes them.
• Connected flow units make up a reservoir.

Drilling

• Drilling creates the well.
• Directional drilling allows for controllable well configurations like long horizontal sections.
• Controlling drilling-induced damage is crucial, especially in long horizontal wells.

Reservoir Engineering

• Reservoir engineering overlaps with production engineering.
• The overlap occurs in the context of study (single vs. multiple wells) and time duration (long vs. short term).
• Single well performance can serve as a boundary condition in reservoir engineering studies.
• Findings from material balance or reservoir simulation enhance well performance forecasts.
• Understanding parameters is necessary to control system performance and characteristics in petroleum production engineering.

Reservoir Hydrocarbons

• A reservoir consists of interconnected geological flow units.
• Modern techniques allow for precise descriptions of the shape and production character of reservoirs, identifying lateral and vertical boundaries and heterogeneities.
• Proper reservoir description is becoming more important with horizontal wells that are several thousand feet long.
• Figure 1-1 shows vertical and horizontal wells within a reservoir, including heterogeneities, discontinuities, vertical boundaries, and anisotropies.
• Understanding geological history is essential for petroleum engineers to understand deposition, fluid migration, and accumulation.
• A reservoir can be an anticline, fault block, or channel sand which dictates the amount of hydrocarbon present and controls the future well performance.

Porosity

• Porosity is the ratio of pore volume to bulk volume in porous media, a direct indicator of fluid in place.
• Porosity values vary, and porosity can be measured with lab techniques using reservoir cores, field measurements, logs, and well tests.
• Porosity is one of the first measurements during exploration.
• Sufficient porosity is required to proceed with exploitation of a reservoir.

Reservoir Height

• Reservoir height, or "pay thickness", describes the thickness of a porous medium between impermeable layers.
• It is referred to as "pay dirt" in vernacular.
• The thickness of the hydrocarbon-bearing formation differs from the underlying water-bearing formation or aquifer.
• Well logging techniques quantify extent.
• Measuring spontaneous potential (SP) helps estimate formation thickness by differentiating sandstones from shales.
• "Gross" and "net" height distinguish the thickness of an entire sequence vs the portion bearing hydrocarbons in layered formations.

Fluid Saturations

• Oil and/or gas are never saturating the available pore space alone
• Water is always present.
• Rocks can be oil-wet or water-wet.
• Electrostatic forces and surface tension create wettabilities, which can change with fluid injection, drilling, or surface-acting chemicals.
• "Connate" or "interstitial" water saturation refers to water present but not flowing.
• Higher saturations than this value lead to free water flow with hydrocarbons.
• Petroleum hydrocarbons are mixtures divided into oil and gas, which appearance depends on composition, pressure, and temperature.
• The terms oil and gas refer to those parts that would be in liquid and gaseous states, respectively, after surface separation.
• Standard conditions are usually 14.7 psi and 60°F.
• Temperature is usually constant, except in high-rate gas wells.
• Attractive hydrocarbon saturation is a critical variable to determine, with porosity and reservoir height, before well testing or completion.
• Formation electrical resistivity is a classic method used.
• Formation brines are good electricity conductors while hydrocarbons are not, this can detect the presence of hydrocarbons.
• Calibrating this can detect and estimate the saturation in pore space, and an SP log are good indicators of saturation.
• Porosity, net thickness, and saturations determine prospect attractiveness and estimate hydrocarbons near the well.

Classification of Reservoirs

• Hydrocarbon mixtures have a phase diagram, where the x-axis is temperature and the y-axis is pressure.
• The critical point is where properties of liquid and gas converge.
• The "bubble-point" pressure exists for each temperature less than the critical-point temperature.
• Only liquid (oil) is present above the "bubble-point" pressure, and gas and liquid coexist below.
• More gas is liberated at lower pressures.
• Reservoirs above the bubble-point pressure are "undersaturated."
• "Two-phase" or "saturated" reservoirs form when the initial pressure is less than the bubble-point pressure.
• The "dew-point" curve encloses the two-phase envelope for temperatures larger than the critical point.
• Outside this curve, the fluid is gas, and reservoirs are "lean" gas reservoirs.
• The "cricondentherm" is the maximum temperature a two-phase envelop can reach.
• Between these points liquid or "condensate" is formed as pressure decreases.
• The "retrograde condensation" region is where reduced pressure results in revaporization.
• Reservoirs with this type of behavior are "retrograde condensate reservoirs."
• Each hydrocarbon reservoir has a characteristic phase diagram and thermodynamic properties.
• PVT (pressure-volume-temperature) properties: Petroleum thermodynamic properties are known collectively.

Areal Extent

• Favorable conclusions of porosity, reservoir height, fluid saturation, and pressure from single well measurements is not enough to decide to develop a reservoir and exploitation schemes.

• Recent advances in 3-D and wellbore seismic + well testing enhance knowledge of reservoir extent, detecting discontinuities.

• More wells drilled enhance knowledge of reservoir peculiarities and limits.

• Areal extent is essential in estimating original-oil- (or gas)-in-place.

• The hydrocarbon volume, VHC, is measured using the following equation: Ѵнс = Аһф(1 – Sw)

• A = areal extent, h = reservoir thickness , & = porosity, Sw = water saturation.

• The height, saturation and porosity vary within the areal extent of the reservoir.

• The equation of (1-2) can lead to estimation of the gas or oil volume under the standard conditions by simply finding a ratio of the volume under reservoir and standard conditions.

Permeability

• Substantial porosity implies interconnected pores, leading to a "permeable" medium.
• Permeability describes the ability of fluids to flow in the porous medium.
• Larger porosity is associated with larger permeability in lithologies such as sandstones; some don't such as chalks.
• Correlations of porosity versus permeability are useful, particularly when considering matrix stimulation.
• Darcy introduced these concepts.
• Flow rate is measured against pressure for different porous media to calculate permeability.
• The flow rate of a fluid through a porous medium is proportional to the head or pressure difference and a characteristic property of the medium.
• Equation: u α kΔ p
• k = the permeability
• Darcy's experiments used water.
• Permeability must be divided by the viscosity when using fluids with other viscosities.

Zone near the Well

• The zone surrounding a well can be altered.
• Drilling, cementing, and well completion alter the reservoir condition.
• Matrix stimulation improves the near-wellbore permeability.
• Cementing supports the casing and provides zonal isolation.
• Zonal isolation prevents contamination of produced fluid from other formations or the loss of fluid into other formations, a common issue of open hole completions.
• "Open-hole:" if no zonal isolation or wellbore stability problems.
• A cemented and cased well is perforated to communicate with the reservoir.
• Slotted liners are used without cementing if wellbore stability is unlikely to be encountered.
• Screens are placed between the well and the formation to combat sand or fines production.
• Gravel packing further safeguard and keeping permeability-reducing fines away from the well.
• Directional drilling leads to deviated and horizontal wells.
• These configurations increase exposure to the reservoir.

The Well

• Fluids enter the well-head and must be lifted through the well to the surface.
• There is a flowing pressure gradient between the bottomhole and the wellhead, and it is dependent on the depth and the well length.
• "Natural lift:" Sufficient bottomhole pressure to lift the fluids to the top.
• Artificial lift: Insufficient bottomhole pressure, and mechanical lift can be supplied by a pump or reduce the density of the fluid in the well e.g by injecting lean gas, this is known as "gas lift."

Surface Equipment

• Fluid is directed towards a manifold after it reaches the top, and this fluid, is an assortment of the oil, gas and water.
• Historically, oil, gas, and water are largely separated at a surface processing facility, and not transported long distances as a mixed stream..
• Exception: some offshore fields, where production from subsea wells can be transported before phase separation.
• Separated fluids are transported or stored.
• Formation water is disposed underground through reinjection.

Objectives of Production Engineering

• the productivity index: the culmination of all components of the petroleum production systems
• the role of a petroleum production engineer:maximize well productivity cost-effectively.
• understanding and measuring productivity index becomes imperative.
• an analogous express for gas an two-phase wells is written below for oil.
• Formula: J = q/p-pwf = kh/α, Βμ(pp + s)
• Equation (1-6) succinctly describes what is possible for a petroleum production engineer.
• First, the dimensionless pressure PD depends on the physical model that controls the well flow behavior, some of which include transient or infinite-acting behavior, steady state (where pD= In re/rw) or others.
• For a constant reservoir with (k:permeability, h:thickness) and with a consistent fluid with (B: formation volume factor, u: viscosity), the adjustable variable on the right-hand side of Eq. (1-6) is skin effect, s.
• Skin effect can be lowered or remedied by matrix stimulation or mechanical means, and a negative skin effect can be achieved with successful hydraulic fracture.
• Stimulation can improve the productivity index, and In reservoirs with pressure drawdown-related problems (fines production, water or gas coning) will increase the productivity index.

Well Productivity and Production Engineering

• Increasing the drawdown (p - pwf) by lowering pwf is the option to increase the production engineer.
• with the productivity index remain constant, the reduction of flowing bottomhole pressure would increase (p-pwf) and flow rate/q increase accordingly.
• Flowing the bottomhole pressure has its losses minimized between the bottomhole and the separation facility, and optimizing the stream from the bottomhole all the way to the surface location is a major role of the production engineer.

Organization of the Book

• Well performance evaluation and enhancement are charges.

• Tools for well performance:

  • The measurement of the relationships for flow paths from the reservoir to the separator.
  • Evaluate the reservoir for potential flow with well testing.
  • Production logging to describe flow into the wellbore.

• With hand-help information, the production engineer can then focus on the engineering to optimize the productivity,.

• Remedial steps can range from well stimulation steps to the resizing of surface area.