The Brigadier Formation is a thinly bedded reservoir that contains approximately 40% of in-place gas resource in Wheatstone field, which underpins the two-train Wheatstone liquefied natural gas (LNG) project in Western Australia. The development drilling campaign has recently been completed with three Wheatstone development wells targeting the Brigadier formation in the northern part of the field. Accurate and timely determination of net reservoir thickness is crucial not only for evaluating field volumetrics and performance, but also to support time-sensitive drilling decisions. In the case of two of the Brigadier wells, the decision to accept a development well location or move to a contingent well location was required within 72 hours of penetrating the reservoir with a pilot hole. Additionally, TD (total depth) decisions in the Brigadier Formation were made on the basis of real time kH (cumulative permeability thickness) evaluation from logging-while-drilling (LWD) logs and are essential for balancing well deliverability requirements with minimising risk of early water breakthrough by optimising standoff from the aquifer.
A fit-for-purpose approach to calibrate and evaluate net reservoir in the thinly bedded Brigadier Formation will be discussed. Several methods of net reservoir determination have been tested in the Wheatstone field. Standard resolution methods like density-neutron cross-over, and photoelectric factor, and high resolution methods like electrical image logs - water-based formation micro-imager (FMI) and oil-based new generation imager (NGI) - and LWD alpha processed density are compared against core-based sand counts to derive the most reliable and fit-for-purpose method of net reservoir determination. Mud-type, conveyance methods and borehole condition also impacts the results of net reservoir evaluation.
The results from a combined density-neutron-photo electric factor method was found to compare very well to core net reservoir and image log-derived net reservoir, across mud types, reservoir fluids and hole angles. It is locally calibrated and blind-tested successfully across different wells. The nuclear tools are logged in every well in the field so this method of calculating net reservoir could be applied consistently across all wells. An added advantage is that the evaluation of net reservoir is independent of porosity and hence, net reservoir will not need to change with different generations of petrophysical evaluation.
The amount of information generated when each well is drilled has increased in volume over the years. Integrating these different forms of information so they may be compared and used when planning new wells has become a challenge. Additionally there are different companies that capture the same data type but present it in different formats, adding to the communication complexity. There is the aded challenge of how to utilise old data that is not in the new formats, this data may be in the form or spreadsheet databases, word processor documents or sometimes in hard copy that cannot be searched electronically unless it is in good enough condition that it may be scanned and then Optical Character Recognition (OCR) may be used.
These challenges increase when companies take over assets from other companies that have used different software to capture their data. The company that has taken on the new asset must now take on new software if it wishes to analyse the well information that it has received. This requires the generation of new workflows or attempting to export information across different software systems, which can be very challenging.
Two approaches are available, either ensures that all companies work to a common format for the information, of use bridging software that can read all of the different types of data and then present it in a simple format that is makes the data usable.
This paper looks at the use of an overarching Data Management system that can accommodate many different forms of data and then present that in a format that allows the faster and more accurate quality control and decision making.
Zhongxian, Hao (RIPED, PetroChina) | Peng, Huang (RIPED, PetroChina) | Shijia, Zhu (RIPED, PetroChina) | Lixin, Zhang (RIPED, PetroChina) | Dianfeng, Liu (Jilin Oil Field Company) | Cai, L. (Jilin Oil Field Company)
Currently, rod-tubing wear and suck rod failure are two serious problems in many oil fields in China. Because of the problem, in some area, the average mean-time-between-failure is only 200 days. The workover costs lots of money, not including the loss of oil production. In view of the low daily output situation of CNPC, problems have not been solved effectively until the development of the innovative ESPCP system.
A permanent magnet synchronous motor (PMSM) was developed and deployed in the bottom of the system, allowing adjusting the rotation speed between 50-500 rpm, which could satisfy the requirement of the PCP. The system included a motor protector, a cardan joint and a PCP from bottom to top.
In the initial field trial, we met many problems, such as the motor protector didn’t work suddenly, the shaft of the cardan joint broken, the system couldn’t run because of the tubing full of heavy oil. According to the specific problem, we improved the design of some components.
More than 10 systems have been deployed and the longest working life is over one year. The system saves 20% energy in average comparing with the pumping unit. It results in fewer operations and reducing the total cost of ownership. The configuration reduces the surface footprint and environmental impact of the oil field. It also reduces deployment and workover and results in fewer and safer operations.
This paper presents some problems and improvements of the system, and analyzes the advantages of the technology.
Restoring well integrity with through-tubing intervention straddles is a relatively common activity. It is normally a lot less complex and less technically challenging than a more expensive well completion workover. However, a particular well in the North Sea was far from straightforward and presented a near impossible intervention challenge. The production tubing was severely buckled, which significantly reduced the effective tubing drift to depth and it was evident that the solution required extremely robust intervention equipment.
The well was completed as a primary sand column oil producer. The well experienced extensive corrosion and suffered from complex well integrity challenges. Initial attempts to restore well integrity were not successful, primarily due to the reduced tubing drift. Calliper interpretation software was used to identify the areas of significant corrosion within the tubing. Wellbore modelling revealed severely buckled tubing above the required straddle setting depth. The operator was forced to source a slim straddle design which was capable of passing through the tight restrictions.
The Anchored Production Straddle (APS) was the solution, with its small OD and relatively large ID. The APS was then customised to accommodate the depth and length parameters of damage within the well. The APS was successful in returning a challenging well to production and reinstating the production tubing integrity.
Due to the nature of the well, the robustness of the APS allowed for more than 150 downward jars through the tight restriction to deploy to depth. Despite the significant jarring, the APS was successfully set and the post-operation leak detection proved the straddle integrity.
The paper will look at the qualification tests done on the equipment, the execution of the operation, and the behaviour of the well before and after the intervention operations.
Cementing across highly depleted zones and weaker formations requires low density cement systems capable of reducing the hydrostatic pressure of the fluid column during cement placement. If wellbores encounter weak or depleted zones, standard cement cannot be used because the bottom-hole pressure will exceed the pressure gradient and cement will be lost to the formation. Service companies offer cement solutions made light enough to circulate in such situations while retaining the ability to withstand down-hole conditions and maintaining adequate compressive strength to meet regulatory guidelines. Lightweight cements can be achieved using water extension, foamed cement or lightweight microspheres. This paper focuses on the use of lightweight microspheres as density reducing agents. Preliminary experimental data comparing different grades of hollow microspheres is discussed. Cement slurries containing hollow glass spheres and other lightweight hollow microspheres were evaluated while still liquid and after cured. While still liquid the cement slurries were characterized in terms of effective density as a function of pressure. After being cured at room conditions, the resulting cement specimens were characterized in terms of compressive strength. Experimental data suggests that cement compressive strength is mostly independent of the lightweight microsphere strength and strongly dependent on the cement load. Guidelines on the selection of the appropriate microsphere grade are also presented.
Santoso, R. K. (Institut Teknologi Bandung) | Rachmat, S. (Institut Teknologi Bandung) | Putra, W. D. K. (Institut Teknologi Bandung) | Resha, A. H. (Institut Teknologi Bandung) | Hartowo, H. (Institut Teknologi Bandung)
Electromagnetic heating has been recently introduced as an effective technology to enhance production of heavy and extra-heavy oil reservoir. Several investigations using metal oxide nanoparticles have successfully proven to increase the effectiveness of heating process. Nanoparticles act as thermal-conducting agent during the heating process. Thus, heat distribution along the reservoir strongly depends on the nanoparticles distribution (concentration profile along the reservoir). In this study, we develop a mathematical model to characterize the concentration distribution of nanoparticles along the reservoir during injection phase. The model is developed using material balance and fluid flow in porous media. Several empirical correlations are also adopted to describe the adsorption phenomenon during the nanoparticles flow in the reservoir. Using coreflood experiment data of iron oxide nanoparticles, the model is simulated and fitted to look for several constants and confirm the minimum error. From the simulation results, the model matched with tracer data and had small squared error with nanoparticles data.
The initial well proving and early production period of a hydrocarbon field is a valuable and unique period of field surveillance where there is the opportunity to narrow the range of uncertainty for key reservoir properties through the use of inter-well interference testing. The Wheatstone gas field, currently being developed as part of the Wheatstone liquefied natural gas (LNG) project, is located offshore north-western Australia. The start-up of the Wheatstone field, due to the nature of constrained ramp-up for LNG supply and location of development wells provides a unique opportunity for early field life interference testing. This is due to periods of individual well and well combination flows that are ideal for pulse generation and detection, with many development wells observing potential pressure responses while nearby wells are flowing. This paper will focus on the potential of initial well proving flows for pulse testing at the Wheatstone field to capture reservoir information.
Pulse testing can potentially be an important reservoir diagnostic tool, particularly during early production when the field is at initial state. Through considered test design strategy, detection of a pressure pulse in an observed well can be used to infer inter-well reservoir connectivity, connected pore volume and transmissibility. This paper provides a method to refine reservoir pore volume ranges and transmissibility. This will be accomplished through the use of dynamic model derived pulse testing type curves using homogeneous reservoir properties to match observed signals for selected active and observation well pairs within the Wheatstone field.
A suite of dynamic models exist for the Wheatstone field. These models cover a wide range of possible realisations for reservoir outcomes that affect initial static volumes and dynamic responses including structure, reservoir net to gross ratio and petrophysics (porosity, permeability and saturation). Selected dynamic models that reflect the uncertainty in inter-well connectivity, driven by variations in net to gross ratio and petrophysics, were run to develop well proving profiles for selected development wells, with non-active wells observing for a pressure pulse from this activity. Following the reservoir simulation uncertainty study of well proving flows, a homogeneous reservoir property simulation model was developed based on the reference mid case dynamic model, with constant porosity and permeability applied to active reservoir cells in the mid model. A variety of type curve pulse responses were developed for a range of porosity and permeability ranges for well pairs. These homogeneous type curves are then used to match reservoir model responses for the well proving uncertainty study, leading to estimates of potential average pore volume and permeability between well pairs. Thus the use of homogeneous reservoir model matching of interference signals during initial field conditions can be employed to appraise inter-well reservoir property ranges.
Uncertainty assessment in reservoir simulation studies is a crucial issue to quantify future planning risks through the field development scenarios. The uncertainty comes from the lack and sparseness of geological and reservoir data that negatively affect capturing the most realistic geological environment for the reservoir flow simulation. Therefore, the uncertainty should be quantified for more plausible and convincible procedure to make a trustful decision regarding future production plans. In this paper, the uncertainty was quantified with respect to the geological and production parameters through the cyclic implementation of the Gas Assisted Gravity Drainage (GAGD) process in heterogeneous sandstone oil reservoir.
The geological uncertainty assessment includes generating multiple stochastic reservoir models for horizontal permeability and anisotropy ratio. In a successive step, the production uncertainty was assessed with regards to the decision parameters of the cyclic GAGD process simulation. The cyclic production parameters are durations of injection, soaking, and production in addition to the minimum bottom hole pressure in production wells.
To quantify the geological uncertainties, a large number of stochastic reservoir models (realizations) were created honoring geological constraints. Since it is impractical to simulate all these realizations, ranking was applied to select the nine quartiles of P10, P20, and P90 of permeability and anisotropy ration models that represent the overall reservoir uncertainty. The selected realizations were evaluated in the compositional reservoir model to calculate the field cumulative oil production. The full factorial design was implemented to produce 81 reservoir models to quantify the geological uncertainty. After that, the most likely reservoir model was adopted for the production data uncertainty assessment to determine the least uncertain space of the cyclic parameters that leads to true optimal solution. In the production uncertainty assessment, the proxy-based Box-Behnken Design and Monte-Carlo simulation approach was adopted to create and evaluate the training and validation jobs through the compositional reservoir simulation.
The presented successive uncertainty quantification workflow has led to obtain higher field flow response than the base case of default settings of the decision parameters. That was achieved after minimizing the uncertain space of the geological and production data that highly impact the cyclic GAGD process performance.
Wang, Shuai (China National Offshore Oil Corporation Research Institute) | Tian, Ji (China National Offshore Oil Corporation Research Institute) | Tan, Xianhong (China National Offshore Oil Corporation Research Institute) | Wang, Ling (E&D Research Institute of Liaohe Oilfield Company) | Zhang, Shaohui (PetroChina Research Institute of Petroleum Exploration & Development)
The low permeability reservoir development effects can be effectively improved with the use of advanced water injection technology, which means the water is injected several months before the oil production. Advanced water injection can improve the formation pressure in advance, and establish an effective displacement system. However, with the increase of reservoir permeability, the increasing value of recovery tends to decline in advanced water injection. Therefore, it is necessary to study the permeability limits of advanced water injection.
In this paper, the laboratory experiments of the low permeability natural core from A oilfield were carried out, and the changes of core permeability, pore structure and oil displacement efficiency in advanced water injection were analyzed. Meanwhile, the changes of sweep efficiency and recovery in advanced water injection were figured out with numerical simulation method, and the effect of advanced water injection tested in A oilfield was analyzed.
The results of the laboratory experiments showed that, for the cores of permeability less than 10.0 mD, as the core pressure drops from 19.0 MPa to 17.0 MPa, the permeability declines by 15.0 percentage points. When the pressure is restored, the degree of permeability recovery is 2.0 percentage points. Also, with the pressure increase, the oil displacement efficiency of the core permeability less than 10.0 mD increase 1.2 percentage points, while the oil displacement efficiency of the core permeability above 10.0 mD increase only 0.3 percentage points. The results of numerical simulation showed that, with the use of advanced water injection in the formation of permeability less than 10.0 mD, the sweep efficiency increases by more than 5.0 percentage points and the ultimate recovery increases by more than 0.4 percentage points.
In addition, the effect of advanced water injection tested in A oilfield was much better than that of the conventional water injection oilfield. The daily single well oil production was 1.6 multiple higher than that of the conventional water injection oilfield, and the annual decline rate was 13.0 percentage points lower than that of the conventional water injection oilfield.
Taken together, the permeability limits of advanced water injection is 10.0 mD, and better development effect and higher recovery can be obtained with advanced water injection technology for reservoirs of permeability less than this value.
This paper can provide a reservoir screening criteria for the advanced water injection technology and can guide the further application of this technology in low permeability reservoirs.
For a reservoir rock to be classified as net, a basic requirement is for it to contain sufficient storage capacity (porosity) and demonstrate fluid flow potential (permeability). Most common methodologies in the industry today for applying net pay cutoffs are developed based on petrophysical measurements. This is especially the case in clastic reservoirs, where a simple approach using a porosity-permeability correlation derived from core or logs is often employed.
The ideal approach is where measurements of both porosity and effective permeability are made in situ. It is worth noting that effective permeability can often be quite different from absolute permeability, hence this measurement must be made for the reservoir fluid and not for the invading mud filtrate and taking into account the presence of irreducible water in a water-wet system. By conducting an in-situ permeability measurement, especially in thin layers or heterogeneous zones, the accuracy of net pay cutoff determination is significantly improved.
In-situ permeability can either be inferred from petrophysical evaluation or measured directly with formation testers. Generally equipped with a probe-type device, formation testers can be combined in a drillstring assembly (formation testing while drilling, FTWD) or run on wireline (wireline formation testing, WFT). In either case, other petrophysical logging tools can be combined and measurements made in the same run. One of the challenges in accurately evaluating net pay with petrophysical measurements or single-probe-type formation testers is their inability to resolve or find thin layers. In laminated formations, logging devices with higher vertical resolution are required and formation testers, rather than attempting to communicate with the formation through a single point source, use devices with large surface areas open to flow, which have proven to provide much more representative measurements.
In this paper the benefits of advanced formation testers and the role they play in net pay cutoff determination in challenging environments are presented.