The key operations needed are separation, injection, and pumping. A description of the technologies in each area suitable for downhole processing is provided below. The most common method of separating liquid (oil or water) and gas is by density difference. Because of the relatively large differences in density between liquids and gas, this separation is normally easier than oil/water separation, where the densities of the phases are much closer. In a conventional vessel, the force of gravity allows liquid droplets to settle from the gas within a designed residence time.
Chen, Changzhao (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Li, Xingchun (China University of Petroleum) | Wu, Baichun (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Zhang, Kunfeng (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Song, Quanwei (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology)
The world has seen a peak in unconventional gas development in recent years. Based on the practice of unconventional gas field development domestic in China and abroad, it is risky that the reinjection water may contaminate groundwater in local or adjacent areas during reinjected fluid migration. Ensuring environmental safety of the reinjection is a multi-disciplinary system project. This paper carries out the analysis and shares the experience of China's practice based on the actual cases from the following aspects. 1) The screening of the well location and the formation of the reinjection. 2) The drilling and cementing construction of the reinjection well, which considers the factors such as cementing quality and cement height and casing material. 3) The estimation of the total reinjection capacity, and the factors such as porosity and permeability of the geologic trap and reservoir fracture pressure is considered. 4) The monitoring of well and migration of reinjection fluids. Further environmental risk study of produced water reinjection is presented in this paper, on both sandstone formation of tight sand gas field and carbonate karst formation of shale gas field in China's typical unconventional gas development areas, using laboratory geochemistry experiments and large area geophysical test to obtain seismic data.
The authors performed a complete experimental laboratory study using suspensions containing solid particles, mono-sized oil droplets, or both. Several coreflooding experiments using highly permeable sandpacks were performed over a long duration, during which significant volumes, sometimes reaching 100 L, have been injected. Also, permeability evolution has been monitored along three sections of each sandpack in order to better understand the dynamic of associated formation damage. A schematic of the experimental setup used to carry out the coreflooding experiments is shown in Figure 1. The suspensions containing solid particles or oil droplets were previously prepared in a 70-L reservoir tank. The tank is made from glass to facilitate suspension stirring and to prevent the aggregation of solid particles within it. The tank’s volume allows an injection over days and nights without interruption. The injection of suspension is ensured by a pump equipped with two low-diameter section pistons to ensure a proper injection of suspension without sedimentation of solid particles.
Instead of being put to productive use, an estimated 140 billion m3 of associated gas (AG) is flared every year, equating to more than $10 billion of resource value. Flaring contributes approximately 350 million tons of CO2 emissions to the atmosphere annually, in some cases having been cited as having a negative effect on the health and livelihoods of local populations. While much progress has been made in recent years to reduce flaring, AG continues to be flared at thousands of oil production sites around the world. A further reduction may be achieved through a market-oriented approach to commercialization that can produce a win-win-win: for the oil producer, the buyer and seller, and the environment. The Difficulties in Commercializing AG AG is frequently viewed by oil producers as an unwanted byproduct of oil production.
Gumarov, Salamat (Schlumberger) | Benelkadi, Said (Schlumberger) | Bianco, Eduardo (Schlumberger) | Woolf, Shaun (Schlumberger) | Hardy, Chris (Schlumberger) | Ido, Hisataka (ADOC Japan) | Tanaka, Manabu (ADOC Japan) | Tominaga, Naohiro (ADOC Japan) | Yahata, Kazuhiro (ADOC Japan) | Okuzawa, Taker (ADOC Japan)
Management of drilling wastes presents major challenges during drilling operations in environmentally protected areas. An Abu Dhabi offshore field development project selected cuttings reinjection (CRI) services as an appropriate solution for waste management.
Although CRI is a proven technology in the region, fracturing injection always inherits its own containment-related risks. To prevent all possible failures that were experienced earlier in the industry globally, a novel real-time monitoring and analysis of fracturing injections data was introduced.
A comprehensive front-end engineering design (FEED) study was performed to evaluate the feasibility of CRI techniques by selecting a suitable injection formation and designing a CRI-dedicated well, surface facilities, slurry testing, and appropriate operations execution plan.
The CRI well was drilled and completed to accommodate waste volumes. An assurance program based on industry best practices was used to support zero solids settling, fracture, or perforation plugging.
To achieve on-time intervention, the first real-time CRI data transfer through a satellite-based network to a support center staffed by global experts in Abu Dhabi was deployed to analyze fracture injection and shut-in pressure responses for early identification of possible risks and to map the fracture waste domain.
The project has been operated successfully since its inception with more than 300,000 bbl of drilled cuttings and drilling waste fluids injected since July 2016. No injectivity issues were experienced during drilling waste fluids injection. Several on-time interventions had been made to prevent well plugging and to maintain surface injection pressures within normal ranges.
Real-time data streaming has made a step-change improvement in the data delivery process, monitoring, and fracture pressure analysis. It creates a direct link between the wellsite and worldwide multidisciplinary technical expertise centralized in Abu Dhabi and provides visualization capability at any time and to any where to all personnel involved in the project.
This step change in monitoring CRI operations provides an acquisition-to-answer" integrated solution, mitigates the injection risks, and enhances the intrinsic value of CRI services.
The paper shares the experience of implementing the novel real-time CRI subsurface injection assurance program dedicated for cuttings reinjection operations. Real-time support from multidisciplinary experts provides live injection monitoring and fracture waste domain mapping for highly complex and risk-prone subsurface injection environments with stringent regulations
Haddad, Mohamed (ADNOC Offshore) | Rashed Al-Aleeli, Ahmed (ADNOC Offshore) | Toki, Takahiro (ADNOC Offshore) | Pratap Narayan Singh, Rudra (ADNOC Offshore) | Gumarov, Salamat (Schlumberger) | Benelkadi, Said (Schlumberger) | Bianco, Eduardo (Schlumberger) | Mitchel, Craig (Schlumberger) | Burton, Phil (Schlumberger)
Injection of drilling waste into subsurface formations proves to be an environmentally-friendly and cost-effective waste management method that complies with zero discharge requirements. It has now become the technology of choice in offshore Abu Dhabi.
The aim of cuttings reinjection (CRI) is to mitigate risks associated with subsurface waste injection and reduce cuttings processing time and cost. In order to meet these goals, a cuttings reinjection subsurface assurance methodology was developed to improve cuttings processing and continuously monitor drilling waste injection operations.
Preparing for CRI operations required extensive drilling cuttings slurry testing to minimize processing time and develop optimum particle size distribution to reduce cost and increase the injected waste volume. The improvements were accompanied by downhole pressure and temperature monitoring of the injection well, thus facilitating analysis of injection pressures. Fracture containment was verified through a combination of pressure decline analysis, periodic injectivity test, temperature survey, and periodic modelling for fracture waste domain mapping. A backup injection well was used also as an observation well to monitor the pressure signitures in the injection formation.
More than 1 million barrels of drill cuttings and associated drilling waste have been safely and successfully disposed of into a single injection zone of CRI well over three years of operations.
The cuttings reinjection subsurface assurance method optimizes grinded cuttings particle size distribution, detects and identifies potential risks to provide mitigation options to prolong the life of the injector.
The proactive subsurface injection monitoring-assurance program was built into the fit for purpose CRI injection procedure to continually avoid injecting any rejected hard material, improve and update the process as per subsurface injection pressure responses, thus reducing processing time and cost, mitigating injection risks, and extending the injection well life.
This paper presents the unique and technically challenging cuttings slurry properties design and pressure interpretation experience learned in this project; the enhancement of cuttings processing helped increase injection volumes and an in-depth interpretation of fracture behavior which behaved like a risk-prevention tool with mitigation options. Significant enhancement was developed in slurry treatment procedures to avoid injectivity loss and maximize the disposal capacity.
Oil, water and gas separation at wellpads with improved technology and compact design has significant advantage for increasing liquid handling from group gathering wellpads and accelerating oil production from fields. Cairn, Oil & Gas vertical of Vedanta Limited is the Operator of RJ/ON block in India with major fields Mangala (M), Bhagyam (B) and Aishwariya (A). Mangala field (75% of MBA production) is the largest onshore oil discovery in India and Bhagyam-Aishwarya fields together contribute to ~25% of the total MBA production. The MBA fields are on water + polymer flood and gradual increase in water production is challenging to process the same oil production volumes. Future field development plans in these fields requires debottlenecking of liquid handling constraints.
The current paper depicts the fast track modifications planned in various fields and its implementation carried out in Aishwariya field which was limited for produced fluid handling due to capacity constraints at the centralized processing well-pad 8 (AWP-08). These modifications were aimed towards localized produced water treatment and reinjection of 30,000 barrels per day (bpd) into the existing injection manifold at Aishwarya Wellpad. In the first stage, produced water is separated from 3,000 ppm to 300 ppm OIW and in second stage from 300 to <100 ppm OIW with <5 ppm TSS. The existing vessels were retrofitted and modified in field with internals like inlet device, calming baffles, coalescing pack, overflow weir and oil bucket. This enabled additional residence time suiting the given fluid characteristics and efficient separation of the produced fluids. This resulted in accelerating oil production from the field by ~2,000 bopd by opening more shut-in wells and leveraging terminal liquid handling capacity. And with the future ESP upsizing and more infill wells coming online, there is further potential to gain additional oil upto 3000 bopd. The execution of Project commenced in Sep-17 and was commissioned in Dec-17 in a record 3 months’ time period including engineering which helped in monetizing early oil production benefit. Based on the success of the local pad separation in Aishwariya field, similar scheme is planned to be implemented in Mangala & Bhagyam wellpads and other small fields with high water production.
As a responsible and sustainable national oil company, the Malaysian Petroleum Management (MPM) of PETRONAS is committed to supporting the Paris Agreement via reduction of global Green House Gas (GHG) emissions by focusing on hydrocarbon flaring and venting optimization as a national agenda. For fields with no means of gas evacuation or reinjection, complying with this national agenda would result in further capital investment for facility improvements or risk curtailment in production that would impact the oil revenue. To realize the reduction of GHG footprint and generate value from condensate recovered from flaring and venting, a patented technology called'Low Pressure - Condensate Recovery System' (LP-CRS) is applied. The LP-CRS is patented under NGL Tech Sdn Bhd and was jointly developed with Vestigo Petroleum Sdn Bhd under the guidance of Malaysia Petroleum Management (MPM) of PETRONAS.
Development of ultra high CO2 field in Malaysia is the next frontier as far as contaminated green field development is concerned. Large hydrocarbon reserve is a major driver to mature technology to support the development of contaminated fields. However, managing the contaminant CO2 is still a major drawback as far as technology is concerned. Base case consideration for CO2 emission mitigation for offshore high CO2 gas fields had always been geological injection even though it deteriorates the overall field economics to a point which may prove to be prohibitive for some field development cases. An alternative method to mitigate CO2 would be the conversion of CO2 to higher value products which provides return in the form of additional revenue or profit. The monetory income from the conversion of CO2 can be utilized to either fully or partly offset the high cost of CO2 injection. This paper attempts to summarise the experience based on feasibility study, technical consideration and lesson learnt by PETRONAS to mitigate the CO2 emissions from the development of such high CO2 gas fields. The summary is done in the context of selecting the suitable CO2 mitigation technology, scale of conversion, maturing the technology and economic consideration as an integral part of the field development.
Integrated asset modelling allows coupling fluid behavior in the full production system, from the reservoir to the facilities. This approach is crucial when different field development scenarios need to be evaluated during concept selection. Different situations must be systematically examined allowing for the optimal operational constraints (rate and pressure limits) and the dimensions of individual elements to be defined, whilst ensuring that material balance considerations are honoured.
Traditionally, reservoir, production and facilities groups separately conduct field modelling and simulations for each element in the system, as part of an iterative process. Reservoir engineers receive facilities constraints and lift performance curves from production engineers as an input. In return, production and facilities engineers receive production profiles from reservoir engineers and design the appropriate facilities capable of safely processing and transporting the produced fluids throughout the lifetime of the project. Any changes in production configuration affect all the models and leads to a need for each discipline to revaluate their simulation models. This process often results in approximations being adopted and frequently raises challenges in the audit trail, as assumptions may be inadequately documented.
Integrated simulation generates representative field production forecasts and the ability to quantify cumulative production and key performance indicators for each scenario. As an example, rates, erosional velocities, pressures and temperatures profiles, compressor and pump requirements and many other variables may be explicitly studied throughout the entire life of the field. This approach reduces the risk of facilities bottlenecking and flow assurance becoming an HSE issue.
This paper describes some of the integrated asset management studies conducted to evaluate different strategies for the development of an ultra-deep water exploratory block, and the key technical factors considered.
For each concept studied, multi-disciplinary models were created to simulate reservoir, tubing, flowline and surface network behaviour for gas condensate, light oil and water production streams. Subsea separation and surface process facilities options were modelled to coordinate the work streams of the different engineering domains, in a coupled solution.
Some complex development scenarios were included. A gas-reinjection case was modelled, where the separated gas from process simulation model is reinjected into the reservoir. Another scenario considered an ultra-deep subsea separation and boosting unit, which was modelled by process simulation software, connected to both the surface network and the reservoir simulation. All were linked with the FPSO process simulation. A range between 5 to 17% of oil gain was obtained in the different scenarios.
As a result of these studies, the decision making process for future investments in the field development plan was optimized.