**3. Upstream facilities**

Several processing steps are required to separate the underground well fluids—a multiphase mixture of gas, oil, water, and solids (both dissolved and suspended) as shown in **Figures 10** and **11**. These separation processes not only include the separation of "produced water" from the oil/gas mixture, but also removal of dissolved gases, acid gases and extraction of light-end distilled products from the crude oil, and the separation of acid gases, water, condensate, and NGL from the associated gases.

The hydrocarbons from wells are transported to gas-oil separation plants (GOSPs) which is generally equipped with a three-phase separator and separate the associated gas and water from oil. The hydrocarbon stream from the three-phase separator might undergo water removal in desalters depending on the crude oil's characteristics. The dry crude is stabilized in the stabilizer column and transferred to terminals either for exports or further processing in downstream facilities.

**Figure 10.** *GOSP process block diagram.*

*Energy Efficiency: The Overlooked Energy Resource DOI: http://dx.doi.org/10.5772/intechopen.101835*

**Figure 11.** *Typical oil & gas separation process.*

Natural gas from dry-gas reservoirs (i.e., non-associated gas) and associated gas from GOSPs are collected at the gas gathering centers and fed to gas processing plants.

At Saudi Aramco, the gas processing plants are classified as part of the "Upstream" sector, whereas in most other parts of the world they are classified as midstream. At our gas processing plants, H2S (used for sulfur production) and CO2 (vented to atmosphere) are removed by *absorption and stripping* processes, while methane and NGL are produced as separate products by low-temperature fractional distillation. After that, NGL is fractionated further in a separate plant into its components (viz., ethane, propane, butane, and natural gasoline (C5+). Finally, sweetened crude oil and gas are distributed to different storage terminals (local, industrial, and international) for shipment to customers. All of the above processes involve several levels of heating, cooling, pumping, compression, expansion, refrigeration, and other supporting operations.

In **Figures 12** and **13** [9], reservoir and natural gas networks in Saudi Arabia are shown.

#### **3.1 Applications in upstream**

The first process after the well-head typically involves a high-pressure test trap, a low-pressure degassing tank, electrostatic dehydrator, electrostatic de-salter, water-oil separator, several types of pumps (booster, shipping, disposal, condensate, wash, stabilizer bottom, transfer, and chemical injection), air compressors, gas compressors, refrigeration compressors, shell and tube heat exchangers, air coolers, a crude stabilizer column, etc. All this equipment and instruments involve multiple utility systems: process water, fire water, instrument/plant air, flare, gravity and pressure sewer, chemical injection, power generation, hot oil, boiler, and steam, etc.

Imbalance and inefficiencies in these systems and equipment have a significant impact on the GOSP, and thus on the overall energy supply chain, so must be carefully assessed and optimized. Typically, in GOSP configuration, essential energy consumers are water injection pumps (39%); gas compressors (44%); and pumps or internal liquids transport and deliver the crude oil via pipeline from the GOSP to the oil terminal or refinery (17%).

#### **Figure 12.**

*The upstream crude oil supply chain network in Saudi Arabia [9].*

**Figure 13.** *The natural gas supply chain network in Saudi Arabia [9].*

Reliability is the main focus in the crude extraction process especially from the underground well to the GOSP. So, while working to improve the efficiency of that stage of the cycle, it is very important to improve other stages from the GOSP to transportation. The following few common measures are widely discussed in the upstream process energy improvement.

#### *3.1.1 Compressors load management and process optimization*

Overall energy efficiency of a compressor is the ratio of absorbed energy by the process gas to the energy consumed by the driver. Compressor load management means ideally turning only the minimum number of units in the network, and optimizing the load on each one according to the demand. This needs to be controlled and monitored with enough time delay function to reduce frequent

*Energy Efficiency: The Overlooked Energy Resource DOI: http://dx.doi.org/10.5772/intechopen.101835*

#### **Figure 14.**

*Performance curve and system resistance curve for a typical compressor system.*

activation/inactivation. The use of variable speed drives may or may not be the best option, since it is difficult to control flow rates under turn-down conditions where the system curve may be nearly parallel to the compressor curve (see **Figure 12**). Properly controlled compressor load management can bring 3–5% savings from total compression.

The methodology for estimating savings potential from load management of compressors is similar to that for pumps, except that the fluid is gas instead of liquid in the pump. In general, the head vs. capacity curve (also called the "performance" curve, **Figure 14**) for a centrifugal compressor operating at a fixed speed is relatively flat, with the total head at the minimum throughput (the surge point) typically being only 105–115% of the head at design throughput. The system curve is also relatively flat because the static head usually dominates the frictional (dynamic) head. The operating point occurs at the intersection of the compressor performance curve and the system curve.

#### *3.1.2 Reduction and recycling through VFD and impeller trimming*

The compressor operation can be controlled, within limits, by installing a variable frequency drive (VFD). For extreme cases where the machine was grossly oversized for the duty and if the desired flow reduction is permanent, impeller trimming may be preferable compared to a VFD. The savings can be in the order of 5–10% of existing power and energy.

#### *3.1.3 Fired heater efficiency improvement by controlling the excess O2*

The main operating parameters affecting combustion process efficiency are the flue gas temperature and the excess air ratio. The target FG exhaust temp should be about 50 F above the dew point, and the % of O2 in the flue gas should be 2–3%). Approximately 3–5% savings in fuel consumption can be expected.

#### *3.1.4 Design modification on the fired heater convective/economizers*

Fired heaters transfer the combustion heat from the fuel to process streams. Most of the heat transfer occurs by radiation in the radiant zone, while some of the

#### **Figure 15.** *Fired heater zones.*

heat in the flue gas is absorbed by convection in the convective section (common) and the economizer (not as common) zones (**Figure 15**). The remaining heat in the flue gas leaves the fired heaters through the stack and is lost.

The heater efficiency is defined as the ratio of heat absorbed by the process and the total heat released by the combustion of fuel. Even small efficiency improvements in fired heaters can yield considerable energy savings and green house gas (GHG) emissions reduction due to their large energy consumption. Usually, the fluid being vaporized is preheated in the convective section, while the economizer is used to recover heat into colder process or utility stream such as Boiler Feed Water (BFW). Since most furnaces come with a built-in convective section, to start with, the only remaining heat recovery retrofit opportunity is usually to add an Economizer. Unfortunately, for piping layout and structural support reasons, this is often not economically feasible but could be feasible with a separate economizer at the surface (i.e., not mounted on the top of convection section) connected through the duct.

## *3.1.5 Well-head to GOSP gas turbo expander generator*

A turboexpander (**Figure 16**), also referred to as an expansion turbine, is a centrifugal or axial-flow turbine, through which high-pressure gas is expanded to produce work, and can often be used to directly drive a compressor or generator. Most gas from the wells is produced at high pressure, and after the first knock-out drum in a gas processing plant is usually let down to lower pressures across a valve. Instead of destroying the pressure energy, it could be let down through a turboexpander to recover and could be utilized energy is utilize as shaft power or to generate electricity in a generator.

## *3.1.6 Hydraulic turbine (liquid)*

Similar in concept to a turbo expander, the hydraulic turbine can be used to recover some power from high-pressure liquids being let down to lower pressure. They are effective pumps operating in reverse but are not commonly used in oil and gas plants.

*Energy Efficiency: The Overlooked Energy Resource DOI: http://dx.doi.org/10.5772/intechopen.101835*

#### **Figure 16.** *Turboexpander schematic.*

There are many other energy efficiency techniques available that can be applied in GOSPs, gas plants, stabilization units, and related supporting facilities, which have the potential for significant energy savings. It is estimated that 5–10% of total supply chain energy is used in upstream activities, out of which 15–20% energy savings are possible.
