Section 1 The Oil & Gas Value Chain Oil & Gas Industry has the following chain of value for its upstream activity (simplified, see Figure 1). Exploration Production Sales Figure 1. Simplified Oil & Gas Value Chain The process starts with exploration activity which basically an activity to ‘search’ and discover source of hydrocarbons to be extracted. Exploration process is a high risk activity with high amount investment. The probability of exploration activity to discover hydrocarbons is app. 20% that is 4 out of 20 wells drilled by a company are productive. The process starts from seismic activity and ended with reservoir modeling to estimate & determine the best production method (see Figure 2). A compact narration on exploration process and reserve estimation can be seen in Section 2 Petroleum System. Exploration Production Sales The process of discovering hydrocarbons Reservoir Geophysics Geology Drilling Engineering Do seismic to Determine well Drill well to Determine determine if location to be prove total reserves any anticline drilled existence of oil and reservoir and/or fault & gas model are found Figure 2. Exploration Process Once the reservoir model is built, the process continues in designing the proper production facilities to extract hydrocarbons. Project management and procurement process are critical in this phase. After the facilities are completely built, operations of the facilities are started. Production control system and monitoring system play important role in this phase. Be noted that since the process of extracting the hydrocarbons are based on hydrostatic pressure, throughout the years production rate will be declined since pressure in reservoir will be depleted (See Section 4 Typical Production Profile). To maintain and improve the declined production rate, developmental projects are mandatory (See Section 4 Typical Production Profile). See Figure 3 for detail description of Production Activities. Maintenance also plays important role in assuring the operability of production facilities. It relates commonly with inventory management in term of spare part management.
Exploration Production Sales The process of extracting hydrocarbons Developmental Storage & Facilities Design Operating Projects Transportation Engineers and Process the Projects to The storing of constructs the ‘raw’ increase the oil/condensate proper hydrocarbons always‐ /LPG/LNG and facilities to to be able to declined the extract and meet sales production transportation process requirement rate of gas to hydrocarbon buyers Maintenance Figure 3. Production Process Sales of hydrocarbons can be in form of agreement. See Figure 4 for description. Exploration Production Sales • Gas sales need agreement; since gas can’t be stored (economically), prior to producing gas, company needs to have agreement with buyer • Oil is more flexible, it can be stored and handled with easier care to the buyer Figure 4. Sales of Hydrocarbon
Section 2 Petroleum System Generally, Petroleum System is consisted of Source Rock, Reservoir, and Trap/Seal (see Figure 5). Source Rock is kind of sedimentary depositional rock (formation) that consisted of organic material to produce hydrocarbon (as a place to produce hydrocarbon). The Reservoir is a kind of place (formation) that stores and makes an avenue of hydrocarbon (as a place to store the hydrocarbon). Trap/Seal is a kind of structure/layer that seals the hydrocarbon. Figure 5. Petroleum System Source: oceanexplorer.noaa.gov Crude oil is found in oil reservoirs formed in the Earths layer/ formation from the remains of living things. Crude oil is properly known as petroleum, and is used as fossil fuel. Evidence indicates that millions of years of heat and pressure changed the remains of microscopic plant and animal remains into oil and natural gas. Although the process is generally the same, various environmental factors lead to the creation of a wide variety of reservoirs. Reservoirs exist anywhere from the land surface to 30,000 ft (9,000 m) below the surface and are a variety of shapes, sizes and ages. Estimating reserves After the discovery of a reservoir, engineer will seek to build a better picture of the accumulation. In a simple text book example of a uniform reservoir, the first stage is to conduct a seismic survey to determine the possible size of the trap. Appraisal wells can be used to determine the location of oil‐water contact and with it, the height of the oil bearing sands. Often coupled with seismic data, it is possible to estimate the volume of oil bearing reservoir. The next step is to use information from appraisal wells to estimate the porosity of the rock. The porosity, or the percentage of the total volume that contains fluids rather than solid rock, is 20‐35% or less. It can give information on the actual capacity. Laboratory testing can determine the characteristics of the reservoir fluids, particularly the expansion factor of the oil, or how much the oil expands when brought from high pressure, high temperature of the reservoir to "stock tank" at the surface. With such information, it is possible to estimate how many "stock tank" barrels of oil are located in the reservoir. Such oil is called the Original Oil in Place (OOIP). As a result of studying things such as the permeability of the rock (how easily fluids can flow through the rock) and possible drive mechanisms, it is possible to estimate the recovery factor, or what proportion of oil in place can be reasonably expected to be produced. The recovery factor is approximately 30%‐35% in common, giving a value for the recoverable reserves. The difficulty is that reservoirs are not uniform. They have variable porosity and permeability and may be compartmentalized, with fractures and faults breaking them up and complicating fluid flow. For this reason, computer modeling of economically viable reservoirs is often carried out. Geologist, geophysicist and reservoir engineer work together to build a model which allows simulation of the flow of fluids in the reservoir, leading to an improved estimate of reserves.
Section 3 Original Oil in Place Original Oil in place is the total hydrocarbon content of an oil reservoir and is often abbreviated OOIP, referring to the oil in place before the commencement of production. Oil in place must not be confused with oil reserves that are the technically and economically recoverable portion of oil volume in the reservoir. Current recovery factors for oil fields around the world typically range between 10 and 60 percent; some are over 80 percent. The wide variance is due largely to the diversity of fluid and reservoir characteristics for different deposits. Accurate calculation of the value of OOIP requires knowledge of: • volume of rock containing oil (Bulk Rock Volume, in the USA this is usually in acre‐feet) • percentage porosity of the rock in the reservoir • percentage water content of that porosity • amount of shrinkage that the oil undergoes when brought to the Earths surface OOIP is calculated using the formula: [stb/ standard barrel] Or 3 [m ] where • = OOIIP (barrels) • = Bulk (rock) volume (acre‐feet or cubic metres) • = Fluid‐filled porosity of the rock (fraction) • = Water saturation ‐ water‐filled portion of this porosity (fraction) • = Formation Volume Factor (dimensionless factor for the change in volume between reservoir and standard conditions at surface) Formation Volume Factor When oil is produced, the high reservoir temperature and pressure decreases to surface conditions and gas bubbles out of the oil. As the gas bubbles out of the oil, the volume of the oil decreases. Stabilized oil under surface conditions (either 60 F and 14.7 psi or 15 C and 101.325 kPa) is called stock tank oil. Oil reserves are calculated in terms of stock tank oil volumes rather than reservoir oil volumes. The ratio of stock tank volume to oil volume under reservoir conditions is called the formation volume factor (FVF). It usually varies from 1.0 to 1.7. A formation volume factor of 1.4 is characteristic of high‐shrinkage oil and 1.2 of low‐shrinkage oil.
Section 4 Typical Production Profile Hydrocarbon production rate is always declining over the years. Company needs to have improvement in increasing production with (but not limited to) these ways: • Enhanced Oil/Gas Recovery • Installation of Compressor • Acquiring assets • Development Drilling (new wells) • New Venture (look for new reserve) Production rate Estimated Production (model base) Gap on Design Production increases as developmental project is finished; the time when the project’s done is named Place In Service (PIS) Production rate on plant capacity Plant capacity Project lead time (4 years) // 2010 201 201 1 2 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Figure 6. Typical Production Profile Project lead time is consists of these activities: • Engineering phase of facilities and flow lines • Procurement of required material and services • Fabrication of certain customized parts • Construction of facilities at site • Installation and Commissioning of the facilities (go on‐line/PIS) Which commonly known as EPCI Activity.