Fractures can be first-order controls on fluid flow in hydrocarbon reservoirs. Understanding the characteristics of fractures such as their aperture, density, distribution, conductivity, connectivity, etc, is key for reservoir engineering and production analysis.
Well testing plays a key role in the the characterisation of fractured reservoirs, especially. New advances in the Pressure Transient Analysis (PTA) have enabled the interpretation of production data in a way where the resulting geological scenarios are in better agreement with fracture patterns observed in outcrop analogues.
Traditionally, Drill Stem Test (DST) data have been the primay source of information for well testing. However, we hypothesise that wireline conveyed tools designed for Interval Pressure Transient Testing (IPTT) could yield a more throrough description of the near-wellbore heterogeneities, including fractures.
Hence, we investigate the applicability of IPTT for characterising fractured reservoirs using detailed numerical simulations models with accurate wellbore representation to generate synthetic IPTT responses that can obtained through a next-generation wireline testing tool called SATURN. We particularly focus on cases where fractures are present in the near-wellbore region but do not intersect the wellbore. The study included parameters such as fracture densities and conductivities, distance between fractures and wellbore and the vertical extension of the fractures across geological beds.
The impact of the different fracture scenarios on the pressure transient tests was recorded as characteristic signatures on diagnostic plots (pressure derivative curves). We have called these curves "IPTT-Geotypes"; they can be used to assist the interpretation process of IPTT responses. To the best of our knowledge, this is the first time pressure derivative type curves for IPTT in fractured reservoirs are presented in the literature.
A field example of an IPTT case was analysed using the concept of geological well testing. We integrated the information from petrophysical logs and the IPTT-Geotypes to assist the calibration of a reservoir model developed to represent the geological setting of the tested reservoir interval. The results provided a sound interpretation of the reservoir geology and quantitative estimation of the matrix and fracture parameters.
The aim of this paper is to compare the performance of three horizontal infill wells in a mature field, of which one is completed with autonomous inflow control devices (AICDs). The analytic results are based on the comparison of oil production rates; water cut development and water-oil ratio plots of the wells. All the wells in this study are producing from the same homogeneous sandstone reservoir.
Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production of which one of these wells is completed with slotted liners and the other with AICDs. Both are artificially lifted with high rate electrical submersible pumps (ESPs). The third horizontal well was placed in an area with higher gas saturation, where a completion with casing, cementation and perforation was used. The performance of the horizontal wells is compared against each other.
The use of active geo-steering successfully supported the well placement into the "sweet spot" of the reservoir due to real-time well path adjustments.
It was found that the AICDs choke back a high amount of fluid and keep the water cut at a stable plateau level. This observation underlines the key benefit of using AICDs as when comparing to the other producing wells without AICDs, the water cut is steadily increasing.
Therefore the use of AICDs is a real option for horizontal well completion.
This paper will be useful to those who are in a phase of early well planning, e.g. in a field (re-)development project and have to select the best well concept (e.g. slotted liner vs. AICDs). AICDs have proven their value even in a super-mature oil field by improving production. Further advantages and challenges during operation are discussed in this paper.
Visuray is using its unique X-ray technology to improve downhole imaging. BP has seen enormous payoff from a program to intervene in underperforming subsea wells in the Gulf of Mexico. A coiled-tubing selective perforating and activation system that transmits critical downhole data and measurements in real time is enabling well interventions that previously could not have been executed. This technical paper describes the planning and execution of a multiservice-vessel (MSV) -based hydraulic-intervention campaign in Chevron’s Tahiti field in the US Gulf of Mexico. Intervention and workover operations can significantly affect the structural integrity and fatigue life of subsea-wellhead systems.
Monitoring and reevaluation of petrophysical attributes in a mature field under production for many decades is crucial for optimizing production and further development planning. In this case study, a multidisciplinary approach is deployed for formation evaluation and reservoir characterization using logging-while-drilling (LWD) sensors spanning formation volumetrics, fluid analysis, high-resolution image interpretation, and geomechanics to confirm remaining oil saturations and help identify recompletion intervals. LWD technologies were used in four wells in Sahmah field of Oman to provide an integrated petrophysical and geomechanical field study using a bottomhole assembly (BHA) including gamma ray, resistivity, formation bulk density, thermal neutron, acoustic, high-resolution imaging, and formation pressure testing sensors. A deterministic multimineral petrophysical model was used to derive formation volumetrics and fluid analysis. Geomechanical interpretation used high-resolution microresistivity imaging, acoustic slownesses, and formation pressure data to verify principal stress orientations and to quantify pore pressure and horizontal minimum and maximum stress magnitudes. These data were then correlated with historical data to evaluate sweep efficiency and residual fluid saturations. LWD sensors have proven to provide robust geological, petrophysical, and geomechanical data compared to previous traditional wireline data acquisition.
Luo, Xianbo (Tianjin Branch of China National Offshore Oil Company) | Li, Jinyi (Tianjin Branch of China National Offshore Oil Company) | Yang, Dongdong (Tianjin Branch of China National Offshore Oil Company) | Shi, Hongfu (Tianjin Branch of China National Offshore Oil Company)
The relative permeability test (RPT) plays an important part in production prediction, the law of water cut increasing analysis, the research on recovery factor and the reservoir numerical simulation. The residual oil saturation is one of the most significant parameters of RPT. While literature on the quality control of RPT is limited, the experimentalists make qualitative judgments on the rationality of the key data estimate based on their own experience. A new method is presented to predict residual oil saturation of light oil reservoirs.
Shi, Hongfu (China National Offshore Oil Company) | Yue, Baolin (China National Offshore Oil Company) | Luo, Xianbo (China National Offshore Oil Company) | Shi, Fei (China National Offshore Oil Company) | Xiao, Bo (China National Offshore Oil Company)
The exploration and development of offshore oilfield facing unprecedented challenges include the decline in the quality of oil reserves, increase of invest and strict environmental protection policies. Usually, low permeability reservoir, heavy oil reservoir complex fault block and small reservoir located far from an existing facility are classified into marginal oilfield. More and more marginal oilfield is put on the schedule of development. In the view of economic, The internal rate of marginal oilfield return is lower than the benchmark rate of return of the industry, but higher than the cost discount rate of the industry. An integrated work flow is presented to improve the tap the potential and mitigate the risk of marginal oilfield involved in dependent development of small oilfields, unit exploitation of small oilfield group, simple platform, extended reach well and phased development. The LD oil field is taken as an example to state the strategy of marginal oilfield.
As the scope of deepwater operations increases, the need for cost-effective well servicing is paramount, particularly because of the continued challenges associated with current volatile commodity pricing. One of the first requirements on any subsea deepwater intervention with a horizontal wellhead production tree is pulling the subsea horizontal tree isolation lock mandrel plugs, commonly referred to wellhead or crown plugs. This can be a "show stopper" event if not planned correctly. Because of the critical nature of this action, the majority of operators follow a two-prong approach, with a primary plan of action and a contingency procedure, to help ensure barrier removal proceeds as planned. Although successful removal of the crown plugs is the principal concern, it needs to be completed cost-effectively for the intervention to obtain approval.
The advent of digital slickline (DSL) allows surface readout (SRO) monitoring during the removal and installation of these barriers to provide an increased level of confidence during this important phase of the operation. This paper outlines case studies of the real-time sensors available with the RF communication DSL system that was highlighted previously (
Additionally, the straight pull battery operated extended-stroke downhole power unit highlighted in
New developments as the downhole power generator was ported to DSL are discussed, notably on- command motor controls and SRO, which was traditionally only available in memory. A downhole anchor was added to the toolbox, which can be run in combination with the downhole power generator to expand effectiveness, as new production trees might not allow for a no-go landing shoulder. To address the increased water depths, the 3.59-in. extended-stroke downhole power generator was upgraded to 80,000 lbf pulling force.
Murchie, Stuart (Altus Intervention) | Jørgensen, Erland (Altus Intervention) | Egeland, Alexander (Altus Intervention) | Saetrevik, Martin (Altus Intervention) | Boge, Erik (Altus Intervention) | Hals, Knut (A/S Norske Shell) | Sbordone, Andrea (TIOS AS)
A/S Norske Shell needed to carry out tubing hanger crown plug (THCP) removal from a riserless light well intervention (RLWI) vessel in the Norwegian sector of the North Sea. There were concerns that the conventional application of mechanical jarring with slickline tools could not be used due to the combination of deep water and high sea currents in the specific field. A safer, more controlled and assured method was needed to withstand this extreme environment and provide the certainty of task success.
Theoretical studies and practical testing were conducted at the supplier's test site to verify the impact sea current had on cables and toolstring assemblies. Different scenarios were analysed and the most effective and lowest cost solution was determined. An electric line deployed and powered electrohydraulic stroker device was selected, which did not require any cable actuation to generate the pull forces required to unseat the crown plug.
Toolstring space-out was critical to ensure the stroker anchor was above and clear of the well control package (WCP) and positioned to prevent any inadvertent damage to the lubricator. In addition, a release tool and a shearable stem provided back-up safety capability for well control. A modification to an existing stroker was designed and a prototype built and tested at the onshore facility.
The final stroker toolstring design was tested out successfully on a more benign shallow subsea well, where the highly accurate force and movement control of the stroker, coupled with real-time surface readout, enabled a safe and secure crown plug pulling and installation operation. The targeted operation in a deep-water, high-sea current environment was then carried out successfully, applying many lessons learned and process improvements from the trial well.
In conclusion, the use of electrohydraulic stroker technology was proved to be a viable alternative for crown plug retrieval and setting operations, whilst bringing heightened visibility and control to such an operation.