Improved Oil Recovery by Injection of Water and Gas Dr. Amin Azhdarpour Department Of Petroleum Engineering, Marvdasht Branch, Islamic Azad University, Marvdasht, Iran. E-mail: aminazh22@gmail.com;amin.azhdarpour@miau.ac.ir
Water injection rate determination The water injection rate is calculated based on two scenarios: 1. Unit mobility ratio 2. Non-unit mobility ratio 2
1. Unit mobility ratio: Direct line drive 3
2. Staggered line drive 4
3. Five spot 5
4. Seven spot 6
5. Nine spot 7
b. Non-Unit Mobility Ratio If the mobility ratio is different from unity, the calculated injection rate obtained from these equations must be adjusted using a correction factor defined as the conductance ratio. The actual injection rate is computed as: 8
9
Four stages of a waterflood Craig et al. identified the following four stages of the waterflood as: 1. Start interference 2. Interference fill-up 3. Fill-up water breakthrough 4. Water breakthrough end of the project 10
11
Stage 1. Start Interference The current oil production at the start of the flood is represented by point A on the conventional flow rate time curve. After the injection is initiated and a certain amount of water injected, an area of high water saturation called the water bank is formed around the injection well at the start of the flood. With continuous water injection, the water bank grows radially and displaces the oil phase that forms a region of high oil saturation that forms an oil bank. This radial flow continues until the oil banks, formed around adjacent injectors, meet. The place where adjacent oil banks meet is termed Interference. During this stage of the flood, the condition around the producer is similar to that of the beginning of the flood, i.e., no changes are seen in the well flow rate Qo, as shown by point B. Notice that the reservoir will not respond to the waterflood during this stage. This delay in the reservoir response is mainly due to the fact that the injected water and the displaced oil are essentially moved to fill up part of the gas pore space. 12
Cont Craig, Geffen, and Morse (1955) summarized the computational steps during this stage of the flood, where radial flow prevails, in the following manner: 13
Cont 14
Example An oil reservoir is under consideration for waterflooding. The relative permeability data and the corresponding water cut as well as the reservoir properties are given. Determine the performance of the flood from the start to interference (Kro=1 and Krw=0.4). 15
Solution Time to interference tii = 80.1 days Cumulative water injected to interference Wii = 36,572 bbl Water injection rate at interference iwi = 418.9 bbl/day 16
Stage 2: Interference Fill-Up This stage describes the period from interference until the fill-up of the preexisting gas space. Fill-up is the start of oil production response as illustrated by point C. The time to fill-up, marks the following four events: 1. No free gas remaining in the flood pattern 2. Arrival of the oil-bank front to the production well 3. Flood pattern response to the waterflooding 4. Oil flow rate Qo equal to the water injection rate iw During this stage, the oil production rate is essentially equal to the injection due to the fact that no free gas exists in the swept flood area. The required performance calculations at the fill-up are summarized in the following steps: 17
18
19
Use the appropriate equation given in previous parts (water injection rate determination ) 20
Example Using the data given from previous example and calculate the flood performance at fill-up. Solution: Cumulative water injected to fill-up Wif = 46,550 bbl Water injection rate at fill-up iwf = 358.2 bbl/day Time to fill-up tf = 109.7 days 21
Stage 3: Fill-up Water Breakthrough With continuous water injection, the leading edge of the water bank eventually reaches the production well, and marks the time to breakthrough. The waterflood performance calculations are given by the following steps: 22
23
Example Using the data given in previous example, calculate the flood performance from the fill-up to breakthrough. Solution 24
Stage 4: Water Breakthrough End of the Project After breakthrough, the water oil ratio increases rapidly with a noticeable decline in the oil flow rate as shown by point D. The swept area will continue to increase as additional water is injected. The incrementally swept area will contribute additional oil production, while the previously swept area will continue to produce both oil and water. The calculations during the fourth stage of the waterflooding process are given below: 25
26
27
28
Example Complete the waterflooding performance calculation for previous example by predicting the performance of a producing WOR of 50 STB/STB, given: 29
Solution 30
Improving the efficiency of waterflooding Improved waterflooding processes include: Low salinity water flooding Polymer Flooding Micellar- Polymer Flooding Alkaline Flooding 31
1. Low salinity water flooding (LSWF) The first effects of low-salinity water injection on waterflooding was published in the 1990s by the University of Wyoming. LSW flooding involves injecting brine with a lower salt content or ionic strength. The latter is typically in the range of 500 3,000 ppm of total dissolved solids (TDS), and no more than 5,000 ppm. 32
Mechanism of oil recovery by LSWF Wettability alteration is considered the main phenomenon behind increasing oil recovery. Sandstones: During low salinity water injection into sandstone core, reactions occur and ph increases, causing generation of surfactant, which lowers the interfacial tension between oil and water and increases the water wettability leading to higher oil recovery. Carbonates: Several researchers related wettability alteration by low salinity water to sulfate adsorption on rock surface. Increasing sulfate ion concentration leads to increasing oil recovery because of the role of sulfate ion as a wettability-modifying agent for carbonate rocks to make it more water-wet. 33
2. Polymer flooding What is the main objective of polymer flooding? 34
Mobility control Any process to alter the relative rates at which injected and displaced fluids move through the reservoir. Objective: To improve volumetric efficiency To reduce Mobility ratio (M) as such M equals or less than 1.0. 35
Polymer augmented waterflooding High molecular weight water soluble polymers are added to water to increase water viscosity. Two types of polymers are commonly used: Partially hydrolyzed polyacrylamide (PHPA) Polysaccharide (Xanthan biopolymers) 36
Technical considerations and mechanism Major consideration are regarding: Operating cost Chemical cost Process effectiveness Crude oil price Environmental control How it works? Mobility is reduced by increasing solution viscosity. 37
3. Micellar polymer flooding (MPF) It is a process in which water mixes with chemical and is injected into the reservoir. The chemicals are designed to lower the IFT of the remaining oil. Polymer thickened water is then injected to drive the oil and the micellar to the production well. Micellar fluid: A mixture of surfactants, co-surfactants, oils, salts, and hydrocarbons. 38
Sketch of a Micellar-Polymer sequence 39
The sequence of MPF 1. Preflush - Brine is injected to change (usually to lower) the salinity of the resident brine so that mixing with the surfactant will not cause to absorb on rock surface. Preflushes can be as high as 100% of the floodable pore volume Vp of a reservoir. In some cases a sacrificial agent (cheap material) is added to minimize the surfactant retention in the rock. 2. Micellar-Polymer Slug - This volume, ranging from 5 to 20% Vp in field applications contains the main oil-recovery agent (surfactants). Typical surfactant concentrations range from 1 to 20% on a volumetric basis. 3. Mobility Buffer - This fluid is a dilute solution of a water-soluble polymer and its purpose is to drive the MP slug and banked-up fluids to the production wells. 40
Cont 4. Mobility Buffer Taper - This consists of a volume of brine containing a concentration of polymer grading between the one of the mobility buffer at the front and zero at the back. 5. Chase Water - The objective of this is to reduce the costs of injecting polymer continuously. If the taper and mobility buffer have been designed properly, the MP slug will be produced before it is invaded by the chase water. 41
4. Alkaline flooding In this method an alkaline chemical is injected to the reservoir. The alkaline chemical reacts with certain types of oils, forming surfactants inside the reservoir. Eventually, the surfactants reduce the interfacial tension between oil and water and trigger an increase in oil production. Alkaline flooding is not recommended for carbonate reservoirs because of the abundance of calcium: the mixture between the alkaline chemical and the calcium ions can produce hydroxide precipitation that may damage the formation. Alkaline flooding is also known as caustic flooding. 42
Mechanisms Alkaline react with oil to form in situ surfactant that will reduce the IFT of the oil- water. Other mechanisms are: Wettability alteration Emulsification Oil swelling 43
Alkaline types Different types of alkaline used are: Sodium hydroxide Sodium orthosilicate Sodium metasilicate Ammonium hydroxide Sodium carbonate Ammonium carbonate 44
IFT and Acid Number 45
THE END 46