Background: Almost all water injection pumps in our area are experiencing high temperature reading on lube oil feeding line to the bearings of disposal water injection pumps and motors especially during the summer season where it reaches 71.11 °C ESD Trip Point. The objective was to determine the root cause of this chronic problem and resolve the issue in order to avoid equipment trips as well as increasing the equipment availability. Method: Two methods were being conducted which are observing the lube oil temperature of leaving all bearings and analyze the lube temperature of each bearing outlet individually. The other method is by comparing temperatures measurements that were collected in the locations right after the (Temperature Control Valve) TCV and 1 meter away from the TCV every hour during the day time during summer season. Result: Statistics reveals that the temperature of the oil coming to the bearing is much less than 68.33 °C since some of the oil temperatures reading of oil leaving the bearings are less than 68.33 °C. Likewise, comparing temperatures measurements that were collected right after the TCV to reading collected 1 meter away from the TCV show approximately 10 °C difference in reading whereas the collected reading 1 meter away from the TCV is lower. Conclusion: the temperature sensors (one for the Hi switch, one for the Hi-Hi ESD switch and one for the TCV) are currently installed right after the (TCV). In this location, the liquid is still hot and heat transfer process between both hot and cold liquids is at the beginning phase and not completed yet. Therefore, above temperature sensors will always read the temperature of the hot lube oil especially during summer season from (11:00 a.m. to 3:00 p.m.), Hi-Hi Temperature ESD switch will be activated to trip the pump. This investigation concludes that the temperature sensors shall be re-relocated from the current location to downstream in order to provide time for the hot and cold liquids mix together. Benefits: The equipment availability will be increased as the unnecessary trips and unplanned downtime of the equipment are being avoided. Hence, it increases equipment MTBF. It also reduces number of warning alarms in control room which makes operators to focus in other issues. And most importantly that the reducing maintenance time and cost (approximately, USD 10,000 cost and five days’ work were avoided per each equipment). Example work that has been avoided to resolve the high temperature issue includes checking instrumentation healthiness, cleaning heat exchanger internally and externally, checking the fin-fan conditions, inpecting and testing TCV functionality, and inpecting lube oil tank as well as the piping which incudes the whole system.
The objective of this paper is to investigate and analyze energy saving and process optimization opportunities in upstream surface facilities, from downhole all the way to the gas-oil separation plants (GOSPs), using value Methodology. Function analysis was used to identify those functions that can be reduced, eliminated, or synergized, to minimize GOSP operating and maintenance cost. In this paper, various energy saving and process optimization opportunities in GOSPs were brainstormed, analyzed, shortlisted, simulated, and validated using actual plant data. Process simulation using Hysys was used to model and verify the feasibility of different process optimization opportunities in GOSPs. A 300 MBD production facility was used to benchmark the Hysys simulation model, and to verify the feasibility of these promising energy saving opportunities. All of the successful opportunities were selected, based on their minimum OPEX and CAPEX, using value engineering methodology.
Relevant to maximizing oil recovery, water injection is implemented for reservoir pressure maintenance and to maximize oil sweeping. The water injection involves both surface and subsurface matters. Since the objective is reservoir pressure maintenance and oil sweeping efficiency improvement, the subsurface domain includes reservoir engineering, geology and geophysics as well as the production technology. For surface operations, the water injection operation includes water injection source, water plant operations and water injection infrastructure. Water injection bottle neck and water quality issue may occur and damage the water injection efficiency. An idea of molecule to molecule (M2M) water injection performance review is raised to conduct a comprehensive and collaborative water injection review that involving many and outreach parties such as reservoir engineers, geologists, geophysicists, operation engineers, production chemists, production technologists, maintenance engineers, production planners and process engineers. The opportunity to include technical providers, partner representatives and host government representatives is taken in order to allow an effective discussion and quicken the maturing of relevant solution proposals. Comprehensive end to end review from the point of water source up to the point of producer is done to identify problem at each point, threats and improvement opportunities at every single node within the whole chain. With the M2M, water injection performance review has effectively provided an effective collaborative working environment as well as a learning avenue for young professionals that are involved in water injection matters. Many action items are resulted from the exercise and they are having high impact including safeguarding potential cost of USD 10 million per year for the water injection plant and infrastructure operations. In the short run, no disturbances for oil production and in the long run, the oil recovery can be maximized. Due to some limitation, this paper discusses only the surface water injection operations.
Liang, Jiabo (CNOOC Iraq Limited) | Jin, Liping (CNOOC Iraq Limited) | Li, Wenyong (CNOOC Iraq Limited) | Li, Qiang (CNOOC Iraq Limited) | Laaby, Hussein Kadhim (Missan Oil Company) | Ammar, Ali Jabbar (Missan Oil Company) | Tayih, Ali Ouda (Missan Oil Company) | Muteer, Raad Fahad (Missan Oil Company) | Saadawi, Hisham N H (Baker Hughes, a GE company) | Harper, Christopher (Baker Hughes, a GE company) | Tuck, Jon O. (Baker Hughes, a GE company) | Fang, Yongjun (Baker Hughes, a GE company)
CNOOC Iraq Limited operates three oil fields in Missan Province in Iraq. They are all large onshore oilfields located 350 kilometers southeast of Baghdad. In order to support reservoir pressure, plans are underway to implement a water injection scheme. The injection water comes from three different sources; produced water, aquifer water as well as river / agricultural water. Considering the nature and varying chemistry of the source water, particular attention had to be given to selecting the material for the water injection wells. This paper describes the approach adopted in selecting the materials for Missan fields' water injection system.
Kar, Taniya (Reservoir Engineering Research Institute, Palo Alto, CA) | Chávez-Miyauchi, Tomás-Eduardo (Universidad La Salle México) | Firoozabadi, Abbas (Reservoir Engineering Research Institute, Palo Alto, CA) | Pal, Mayur (North Oil Company, Doha, Qatar)
Low salinity water injection when effective in increasing oil recovery is often thought to be through increase in water wetting. Recently, oil-water interfacial rheology has been suggested to be related to oil recovery from low salinity water flooding. We have also discovered that addition of a very small amount of a functional molecule in the injection brine increases oil recovery significantly. Quantitative effect of interfacial elasticity and the effect of rock on oil recovery is investigated at 100 ppm concentration in this work for the first time. A light crude oil is used in four sets of waterflooding experiments in a carbonate rock. The injection brine is modified by adding 100 ppm of a non-ionic surfactant. To understand the recovery performances, interfacial viscoelasticity, interfacial tension and contact angle measurements are performed using brines of varying salinities. In interfacial rheology the effect of equilibration of the aqueous phase with the rock is also investigated. Additionally, adsorption of the surfactant in the carbonate rock is investigated for various aqueous phases via UVvis spectrometry. Crude oil, calcite and reservoir brine show moderate oil-wetting behavior. Addition of surfactant molecules makes the system more water-wet, however, the change is not pronounced. From coreflooding experiments, addition of surfactant in high salinity brine increases recovery by over 20% which we interpret to be due increase in interface elasticity. The phase angle which is a direct measure of interface elasticity decreases by 70% in an aqueous phase at about 4 wt% salt due to the surfactant. High interface elasticity reduces oil snap off and increases oil recovery. An effective molecule dissolved in water can increase the interface elasticity significantly. In relation to low salinity water injection we have established that there is an optimum salt concentration for high oil recovery. The injection of an aqueous phase without salt gives a lower recovery than injection of say 0.1 wt% salt in the injected water.
We have introduced a new IOR process based on interface elasticity which requires a very low concentration of a non-ionic surfactant. The process is neither through wettability alteration nor through significant change in IFT. The chemical we have used is environmentally friendly and of low cost. It has very low adsorption onto the rock surface.
Induced seismicity from the injection of fluids into the earth remains a significant concern for oilfield activities such as saltwater disposal and hydraulic fracturing operations. The number of induced earthquakes occurring in the oil and gas producing regions of the Central United States and Western Canada has been declining over the past few years, highlighting the successful implementation of improved regulations and effective operational practices. However, technical engineering and geoscience challenges remain. This opening session will explore the current state of learnings and progress since the last workshop in November 2017, and highlight forward opportunities and challenges. Differences in geology, industry practices, population, politics, and other factors lead to various regulatory responses and requirements.
Earthquake in Cushing, OK -- home to the largest oil storage facility in the world -- leads to further regulatory action on disposal wells in the area. Research and development firm Battelle is working on a new induced-seismicity study that aims to help wastewater disposal well operators in Ohio stay on the good side of state regulators. Industry regulators in Oklahoma have rolled out broad new restrictions on more than 600 disposal wells as part of the largest action of its kind taken in response to earthquakes. A surge in earthquakes tightly clustered in southern Kansas that followed the large increase in produced water injections prompted the state to cut the daily limits on disposal wells in that area to see if that will help solve the problem.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A well where produced water is injected back into a deep, usually depleted zone but one that is not connected to the producing pay zones.
In most US unconventional resources development, operators usually first drill the parent wells to hold their leases, and then infill wells are drilled. A challenge raised from this process is the well-to-well interference or frac-hits. Fractures in infill wells have a tendency to propagate toward the depleted region induced by the pressure sink of the parent well, resulting in asymmetric fracture growth in infill wells and frac-hit with the parent well. One of the available mitigation methods is to inject water into the parent well to re-pressurize the depleted region. Though several papers have released positive results from their numerical studies, both negative and positive responses are reported from filed applications. This paper focused on identifying the mechanism and key factors controlling the effectiveness of the subsequent parent well water injection. A coupling reservoir geomechanical model was built to evaluate the pressure and stress change caused by the parent well production and subsequent parent well water injection. The reservoir and geomechanical models are prepared based on a dataset from Eagle Ford Shale. At desired time steps, pressure distribution from reservoir simulation is used to calculate the corresponding stress status.
In this numerical simulation study, both reservoir properties and operating conditions are considered. Considering the production loss during the parent well injection, the maximum injection time is set to be 1 month. The magnitude and orientation of horizontal principal stresses within and around the depleted region are used as a criterion to evaluate the effectiveness of subsequent parent well injection. A general observation is that between two adjacent fracture clusters, 3 regions could be identified whose behaviors are significantly different during production and injection. The subsequent water injection could only restore the pressure and stress in region 1, which is within 10 ft to the fractures. Region 2 is severely depleted but the injection of 1 month generates no improvement in this region due to the low matrix permeability. Region 3 might exist, where oil is not produced, but Shmin reduces and this reduction could not be restored through injection of 1 month. If the injection generates a relatively uniform pressure distribution, then SHmax angle change could be reduced to 0. We also observed that: (1) for our case, an injection pressure equal to the initial reservoir pressure is recommended. Using low injection pressure, Shmin is found out to be lowest in fractures, which may make infill well fractures tend to propagate into and hit the parent well fractures. However, if injection pressure is increased to larger than the initial reservoir pressure and smaller than the minimum horizontal stress, the improvement is insignificant; (2) Comparison between uniform and non-uniform hydraulic fracture geometries shows that hydraulic fracture geometry mainly affects the depletion region far away from the wellbore. i.e. along the long fracture tips. After injection, in the case with long uniform fractures, the Shmin value in long fracture tips is still lowest. (3) An SRV with high permeability significantly extends the depletion region. If the permeability is not large enough i.e. 0.01 mD, after injection of 1 month, the restored Shmin is about 1000 psi lower than the base case without SRV. (4) Using low bottomhole pressure in production, restored pressure and stress are about 500 psi lower than the base case; and due to the large pressure contrast between region 1 and region 2, the SHmax angle change could not be reduced. (5) In a reservoir with normal pressure, as the pressure change is not large, it is easier for the subsequent injection to take effect.
This paper provides significant insights into how to design a successful subsequent water injection process in a parent well, mitigate the negative effects of frac-hits, and maximize production of both parent and infill wells.
The high intensity of hydraulic fracturing in unconventional reservoir has resulted in dramatic increase in water consumption. The reuse of produced water has been driven by both the environmental and economic benefits. The performance of conventional anionic friction reducers is usually affected by the total dissolved solid (TDS) in the water source. We present here a cationic friction reducer which is fully compatible with most of produced water based on results from the lab and field.
A cationic friction reducer was studied in the lab in synthetic brines and produced water from different Basins with TDS up to 275K. Friction reduction was measured at various concentrations of monovalent, divalent and trivalent cations in the brine. The impact of SO42- was also studied as a representative anion. Several field produced water with different level of TDS were also tested to prove the full compatibility. The additional benefit of using this cationic friction reducer is to control the clay swelling demonstrated by CST result. In the field, the cationic friction reducer was successfully applied in the slickwater jobs in North America using 100% produced water, resulting in high pumping rate with low wellhead pressure.
The cationic friction reducer shows excellent friction reduction even in very high TDS. It also exhibits good tolerance to all the cations and anions, most of which usually are problematic for anionic friction reducers. For the jobs performed, the treating pressures were well below the limit at designed pumping rates, and all proppants were placed as planned. The cost saving was significant by using produced water instead of fresh water. The results from the lab and field demonstrate that this cationic friction reducer is a good candidate for wells to be completed with 100% or diluted produced water.
This paper presents a solution to the wells that require or prefer to use produced water in their slickwater jobs. The field data shows that it saves horsepower during operation due to the high friction reduction in produced waters. It also lowers the cost related to produced water disposal and fresh water transportation.