Nunez, Alvaro Javier (Petroleum Development Oman) | Al-Farei, Ibrahim (Petroleum Development Oman) | Benchekor, Ahmed (Petroleum Development Oman) | Al Husaini, Nasser Khalfan (Petroleum Development Oman) | Sayapov, Ernest (Petroleum Development Oman) | Al-Shanfari, Abdul Aziz Salim (Petroleum Development Oman) | Al Bahri, Khalfan Mubarak Khalfan (Petroleum Development Oman) | Chavez, Juan Carlos (Petroleum Development Oman) | Al Hinai, Adnan Saif (Petroleum Development Oman)
Hydraulically fracturing operations is becoming much more complex as the gas formations are being depleted with the time. In addition to this, some gas reserves need to be recovered by fracturing horizontal wells with multiple stages which is the case of an extensive gas field in the Sultanate of Oman that has been producing since 1991 mainly by hydraulic fracturing. The scope of this paper is to discuss the different methodologies in the operations associated to hydraulic fracturing in horizontal gas wells with formations depleted in PDO, the main objective is to show operations and well delivery improvement by the optimization of tools conveyance, perforating techniques, clean out and milling strategy. The paper will show the enhancement of the operations and the outstanding results in these challenging well conditions. The paper will start by describing the different methods used to execute operations for fracturing horizontal wells which are mainly related to plug and perf technique, clean out and milling plugs in between stages. Further, it will discuss the strategy, planning and job execution of one of the wells with 14 stages in the horizontal section, the perforating technique and strategy used to help reduce screen out's, it will also discuss the acquisition of spectral Noise log data post fracturing with the assistance of Nitrogen as well as the milling of the isolation plugs at the end of the job. The optimization of the conventional operations is a novel approach to enhance hydraulic fracturing in depleted horizontal gas wells in PDO, this is in alignment with the continuous improvement ideas and the lean thinking across the oil and gas industry. It is easy to replicate in other horizontal wells to be hydraulically fractured which will reduce cost, HSE exposure and will help increase the recovery of hydrocarbon reserves.
Zou, Jian (CNOOC Ltd, Tianjin Branch) | Han, Xiaodong (CNOOC Ltd, Tianjin Branch) | Liu, Yigang (CNOOC Ltd, Tianjin Branch) | Wang, Qiuxia (CNOOC Ltd, Tianjin Branch) | Zhang, Hua (CNOOC Ltd, Tianjin Branch) | Liu, Hao (CNOOC Ltd, Tianjin Branch) | Wang, Hongyu (CNOOC Ltd, Tianjin Branch) | Han, Chao (China University of Petroleum (East China))
Thermal recovery method with horizontal wells has been conducted in Bohai Oilfield for almost ten years. The horizontal section length of the horizontal well is about 300 m. For thermal wells, monitoring the real-time temperature data downhole is of importance for analyzing the temperature distribution and variation rules along the wellbore, and consequently improving the produced degree of the horizontal wells.
Different kinds of high-temperature monitoring technologies are summarized and the high-temperature optical fiber is selected for temperature monitoring of the offshore thermal wells. The steam injection tubing with functions of temperature monitoring is designed by using the optical fiber. In the horizontal section, the optical fiber is installed inside the steam injection tubing, goes outside of the tubing through a Y-joint, and connects to the surface along the annulus. Thus, the optical fiber could monitoring temperature of both the horizontal section and the annulus. Two target well are selected for project design and put into field application during the steam injection process. The monitoring results show that the high-temperature optical fiber works normally for about one month while the steam injection temperature is about 350°C. Besides, with the real-time temperature monitoring, the upward movement of the steam in the annulus is also observed and controlled by adjusting the Nitrogen injection parameters in the annulus.
This is the first time that the optical fiber technology is applied in offshore thermal wells, which would be important for verification of wellbore parameter calculation and analysis of the casing variation when heated during the steam injection process. The successful application of the optical fiber in offshore thermal well would provide a guidance for the subsequent offshore thermal exploitation.
This paper describes preparations and planning for a campaign of foam gas shut-off pilot operations in a large carbonate reservoir located offshore Abu Dhabi containing an oil column in equilibrium with a large gas cap. Throughout the field history and due to the heterogeneity (permeability ranges from 5 mD to 1 D), the major challenge to produce the oil rim independently from the gas cap was how to control premature gas breakthrough in the oil producers. Mechanical interventions in high gas-oil ratio wells are particularly complicated due to the risk of losing oil potential and are generally unsuccessful.
Injection of foam for gas shut-off (FGSO) is a near-wellbore treatment, which has been trialed elsewhere in the industry with some success. Foam can act as an auto-selective agent to shut-off confined gas inflow through a gravity-controlled source like coning or cusping, while oil breaks the foam, resulting in preferential oil flow and reduction in gas-oil ratio. In addition, this type of operation has been identified as an EOR enabler, because it can help prepare for the technical and logistical challenges of using EOR chemicals in the field, generate data useful for the modeling of surfactant and polymer under reservoir conditions, and mitigate early gas breakthrough in the case of gas-based EOR developments.
For the reservoir in question, a key complicating factor was to identify a surfactant, which could generate strong foam in-situ (mobility reduction factor of 50) at harsh reservoir conditions (temperature of 220-230 °F and water salinity above 200,000 ppm, including 20,000 ppm divalents), with an acceptable level of adsorption. The candidate selection process took into consideration overall behavior of the reservoir as well as performance of the individual high-GOR wells. Target well selection criteria included homogeneity of permeability, an understanding of gas sources and their movement, and observation of a rate- or draw-down-dependent GOR.
The experimental lab program involved testing several surfactant formulations in bulk as well as in corefloods with and without the presence of reservoir oil to evaluate foaming ability and level of gas flow reduction. One formulation showed the right level of in-situ mobility reduction, in addition to stability and moderate adsorption at the prevailing reservoir conditions, and was therefore selected for a pilot test involving four wells.
Lightweight or, alternatively, foamed cement slurries for surface casing operations are often necessary during special situations (i.e., low fracture gradients) for the required zone to be isolated. The foamed cement technique reduces the heat of hydration (HoH) of the slurries, reducing potential risk of shallow hydrate flow and losses because of its reduced hydrostatic pressure. This alternative for lightweight slurries has been used globally with successful results.
The foamed cement operation was designed and executed considering specific aspects and details, including a combination of factors, such as expected low fracture gradient, mechanical property requirements, logistic constraints in terms of the difficulty managing two types of cement (large tonnage of Blend and G cement vs. rig capacity and safety volume requirements), long sections to be cemented, and the uncertainty of the cement volume excess necessary to achieve return in the seabed. Because this was the first cement operation for the operator at this remote deepwater field, the planning phase required extensive discussions. Rig silo capacities and deck space on the rig were limited, which constrained the possibility of considering backup for all bulks, chemicals, and equipment.
Execution of the cement operation was as per the approved program without deviation. The cement volume returned at seabed indicated an openhole diameter with ±100% washout. A tracer additive (fluorescent dye) mixed with the spacer was successfully used to indicate fluid return at seabed (2120-m water depth). As part of the best practices to execute this operation, a liquid additive system was used to provide pump volume flexibility. Foamed cement laboratory tests were performed, considering field samples and the foaming agent (surfactant) were injected straight at the suction of the pump. As expected, the foamed cement operation is an extremely efficient and effective technique to achieve zonal isolation in a surface casing string of a deepwater well. Currently, this procedure is frequently used in fields globally. A case study of the first foamed cement application for surface casing in French Guiana is discussed.
Many of the oil reservoirs in ADNOC’s portfolio have been producing for decades and continue to deliver their target rates, thanks to development schemes centred on pressure support from peripheral water injection and/or crestal gas injection, where applicable, or from line-drive patterns.
As these reservoirs mature, a number of enhanced oil recovery (EOR) techniques are being evaluated to increase the ultimate recovery factor. Choosing one or several appropriate EOR methods starts with a robust screening methodology, which in this case has to apply across an entire reservoir portfolio, rather than just to a single asset.
The key objective of the screening efforts presented in this paper is to estimate the EOR potential from each reservoir in a systematic manner to allocate the right resources, to the right fields, at the right time, with the right technology. Therefore, the screening methodology must take into consideration the following aspects: The focus of the screening is on identifying opportunities, which are or will become technically feasible by the time deployment is required The screening procedure must remain sufficiently high-level to be able to deliver an outcome within a short time-frame A single EOR method is not necessarily applicable across an entire reservoir; hence several EOR methods can potentially be implemented in the same reservoir but in different areas The thought process (workflow) has to be properly documented so that the screening exercise can be updated whenever new technologies or new relevant field data become available
The focus of the screening is on identifying opportunities, which are or will become technically feasible by the time deployment is required
The screening procedure must remain sufficiently high-level to be able to deliver an outcome within a short time-frame
A single EOR method is not necessarily applicable across an entire reservoir; hence several EOR methods can potentially be implemented in the same reservoir but in different areas
The thought process (workflow) has to be properly documented so that the screening exercise can be updated whenever new technologies or new relevant field data become available
The new EOR screening tool considers more EOR methods compared to previous screening efforts: It takes a much broader view on potential source gas options for miscible gas injection, namely enrichment of sweet hydrocarbon gas, sour gas streams, CO2 with or without impurities, as well as nitrogen for some high-temperature reservoirs containing volatile oil. This step involved estimating miscibility conditions for hundreds of combinations of injection gas compositions and reservoir fluids using equation-of-state based MMP calculations in addition to common MMP correlations. The reservoirs are all carbonate formations and are characterized by high temperature and high salinity. These conditions have traditionally been a challenge for chemical EOR methods involving polymers and surfactants. However, recent R&D progress has opened up for opportunities not previously considered. Both polymer and foam agents are currently being piloted, which have the potential to change the EOR landscape in Abu Dhabi and perhaps elsewhere as well. As reservoirs mature and breakthrough of injection fluids begin to occur, the need for improved reservoir conformance becomes evident. The success of any EOR technique relies on the right well placement with the right monitoring in place and the right level of injection profile control.
It takes a much broader view on potential source gas options for miscible gas injection, namely enrichment of sweet hydrocarbon gas, sour gas streams, CO2 with or without impurities, as well as nitrogen for some high-temperature reservoirs containing volatile oil. This step involved estimating miscibility conditions for hundreds of combinations of injection gas compositions and reservoir fluids using equation-of-state based MMP calculations in addition to common MMP correlations.
The reservoirs are all carbonate formations and are characterized by high temperature and high salinity. These conditions have traditionally been a challenge for chemical EOR methods involving polymers and surfactants. However, recent R&D progress has opened up for opportunities not previously considered. Both polymer and foam agents are currently being piloted, which have the potential to change the EOR landscape in Abu Dhabi and perhaps elsewhere as well.
As reservoirs mature and breakthrough of injection fluids begin to occur, the need for improved reservoir conformance becomes evident. The success of any EOR technique relies on the right well placement with the right monitoring in place and the right level of injection profile control.
In this paper, we investigate the potential for applying miscible nitrogen injection as an enhanced oil recovery (EOR) method for a high-temperature, low-permeability carbonate reservoir, which contains a volatile oil with some H2S and CO2. The field, which is located onshore Abu Dhabi, is still in its early development phases but suffers from relatively low throughput rate because of low permeability. Various gas injection schemes are being considered, with different source gases. At the prevailing reservoir pressures, extensive phase behavior studies confirm that the reservoir fluids develop miscibility with nitrogen, carbon dioxide, and hydrocarbon gas.
The simulation studies involve a number of sensitivity runs performed on sector models, which are sufficiently fine-gridded to capture the compositional transition zone propagating between injector and producer pairs. Miscible nitrogen injection comes out as a viable option with the potential to increase recovery by 10 to 20% above the current water flood development scheme. The significantly improved sweep and displacement efficiency are due to N2 miscibility with reservoir oil under reservoir conditions, possibility of increased PV injected in a N2 WAG scheme, and the ability to maintain a higher reservoir pressure (at initial reservoir pressure).
From a surface facilities point of view, techniques for N2 capturing is mature, tried and tested. N2 being inert does not pose corrosion risks to well completion and surface facilities. However, capital costs for N2 rejection units – if utilised in a N2 WAG EOR scheme – will need to be taken into account. Although N2 WAG EOR is seen to be very attractive for the reservoir under study, alternative EOR schemes are also being actively evaluated. The aim is to arrive at an optimum EOR project for the reservoir in line the achieving the 70% oil recovery aspiration.
Downhole wet gas compression technology (DHWGC) is a relatively new artificial lift concept for gas wells that aims to boost production, maximize recovery and delay onset of liquid loading. By definition, wet gas compressors are capable to handle certain amount of liquids entrained in the gas, however, there are some circumstances where large amounts of liquids accumulate below the compressor and need to be removed to allow the gas well to flow. Liquids can accumulate below the downhole compressor after well intervention or as result of condensates accumulation during normal production. To this end, a means to enable liquids removal for Downhole wet gas compression applications must be developed. The objective of this study was to identify completion solutions that enable liquids unloading below the compressor. This paper introduces a new concept with a simple well architecture that will enable continuous operation and eliminate needs of additional well interventions to remove liquids accumulation that occur during well shut-in operations.
Today, small-scale liquified natural gas (SSLNG) plants are planned and built in different areas around the globe. Due to the overall market situation and competition, these projects are challenged to decrease capital expenditure (CAPEX), while becoming increasingly efficient to meet mid-size investors' operating expenditure (OPEX) targets and return on investment (ROI) expectations. The main challenges are the overall efficiency of the plant, seal leakage rates, operational flexibility and the plant's space limitations.
To a big extent, the aforementioned points are closely connected to liquefaction technology selection (either single mixed refrigeration or nitrogen Brayton cycle) as well as the rotating equipment used: Firstly, regarding energy use, the refrigeration compressor is the main power consumer in an SSLNG plant (in addition to pumps and smaller compressors). Secondly, a large amount of process leakage is linked to the seals of the rotating equipment. Regarding the third point, operational flexibility, this parameter is closely related to the deployed compressor and expander, and their respective process characteristics. Lastly, the footprint and equipment size have an impact on the installation costs and ultimately CAPEX.
Often, especially in a nitrogen Brayton cycle, compressors as well as warm and cold turboexpanders are supplied as single skid each: that is, a nitrogen compressor skid as well as both warm and cold expander compressors installed on another skid. To reach their future objectives, some SSLNG plant operators are taking new approaches that combine these two technologies: compressor and expander applications are installed on one single gearbox and skid – this is called a Compander. This approach is already used in other industry segments and applications, including LNG carriers. Atlas Copco's first land-based LNG refrigeration Compander was installed back in 2002 at a plant in Norway. The Compander design allows for only one gearbox on which compressor and expander stages are mounted, one oil system, one control system and one seal gas panel – instead of having all of these components twice. By applying these bridging technologies, SSLNG plants are finding new ways to improve OPEX while at the same time reducing the financial burden on new projects. In this case study, we discuss how SSLNG plants in Norway and customers in other places have implemented Atlas Copco Gas and Process integrally geared technology that merges the functions of a centrifugal compressor and turboexpander into one compact Compander unit. In addition, different configurations of separate compressors and expanders are discussed and compared to a single-skid (Compander) solution.
During the discussion, the benefits of a Compander compared to single and separate equipment designs are evaluated.
One of the main challenges in Steam Assisted Gravity Drainage (SAGD) wells is steam breakthrough in producer wells, which can result in inefficient bitumen recovery due to high Steam Oil Ratio (SOR). Flow Control Devices (FCDs), also known as Inflow Control Devices (ICDs), have been developed for several years to balance the oil inflow along the horizontal wells and consequently delay or mitigate the unwanted fluid breakthrough. The newest generation of FCDs is a truly Autonomous Inflow Control Valve (AICV) which can optimize oil production, reduce SOR and significantly restrict the inflow of unwanted fluids such as water, steam and Non-condensable Gases (NCGs).
This novel AICV design was tested in a full-scale high temperature laboratory flow loop that replicates the downhole operating temperatures, fluid conditions and flow rates of a SAGD production well. The full-scale tests were conducted to determine how the AICV could optimize SAGD production by restricting the production of NCGs and steam and favor the production of oil.
Both single-phase and multi-phase flow performance behavior of the AICV are presented. Furthermore, the results are compared with a conventional passive ICD to illustrate the significant potential of the AICV in enhancing oil production, total recovery and overall project economics.
The results show that the production of lower temperature, relatively high viscosity oil can be increased by approximately 90% for the situation of deploying AICVs. Additionally, gas production is dramatically reduced from approximately 1200 L/h for the ICD, to 180 L/h with the AICV, corresponding to an 85% reduction. These results show that a considerable reduction in steam use is possible by using the AICVs, which would result in reduced energy usage for steam generation, reduced water usage, and reduced greenhouse gas emissions for each barrel of oil produced, thus improving the economics of SAGD projects.
Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. The injected gas composition varies between projects, but is typically hydrocarbon gas, sometimes enriched with intermediate components to ensure miscibility, or carbon dioxide in regions such as the Permian Basin, where supply is available at an attractive price.
Miscible nitrogen injection into oil reservoirs, on the other hand, is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility. Unlike other injection gases, the minimum miscibility pressure for nitrogen decreases with increasing temperature. In fact, in deep, hot reservoirs containing volatile oil, nitrogen may develop miscibility at a pressure similar to the MMP for hydrocarbon gas or carbon dioxide. The phase behavior is more complicated than what can be captured by correlations and hence requires equation-of-state calculations.
Results from a recent EOR screening study in ADNOC indicate that a couple of high-temperature oil reservoirs in Abu Dhabi may be potential targets for miscible nitrogen injection. This paper discusses key aspects of the EOS modeling. Advanced gas injection PVT data are available to enable a fair comparison between nitrogen, carbon dioxide and lean hydrocarbon gas. In this work, we have modelled and analyzed the phase behavior of two volatile oil systems with respect to nitrogen, hydrocarbon gas, and carbon dioxide injection, as part of a reservoir simulation study, which will be covered in a subsequent publication; see