Asia's first rigless subsea stimulation was executed in 2018, with intervention performed upon three target wells offshore Sabah Malaysia, at a water depth of approximately 1400 m (4,593 ft). Significant changes in reservoir performance prompted an acid stimulation and scale squeeze treatment, designed to remedy fines migration and scaling issues within the well and production system. Treatment fluids were delivered subsea by an open-water hydraulic access system, using a hybrid coiled-tubing downline. Access to the subsea trees was permitted via a patented choke access technology, allowing for a flexible, opex-efficient, and low-risk intervention. The intervention system was installed upon a multi-service vessel, with the downline deployed via the vessel moonpool. A second support vessel was used as required to provide additional fluid capacity without disturbing primary intervention operations. This enhanced the flexibility of the operation, permitting changes in the treatment plan to be accommodated for without impact to critical path stimulation activities.
The full intervention was delivered as an integrated service, with all elements supplied by a single provider, via one contract. An established network of in-house equipment, expertise, test laboratories, and operational bases supported the planning and execution of the project. This was complemented by select external providers for vessels, remotely operated vehicle services, and other specialist contractors.
The challenges faced during this new market entry included completion of a comprehensive treatment fluid test program, importation and logistics of equipment from around the globe, and managing operational risks, all within a condensed timeline to satisfy a brief intervention window. By leveraging the diverse global network of the service provider, the technology and people required for the project were accessed and brought together to achieve a collaborative solution. This was enhanced by the inclusion of performance based elements within the contract. The provision of a highly efficient and flexible well access technology also supported rapid mobilization and operational risk reduction.
Post-stimulation well testing confirmed an average increase in oil productivity of 86%, with a corresponding productivity index factor (PIF) gain of 3.4. These results, combined with the efficient execution of the campaign, confirm the appropriateness of open-water hydraulic access using coiled-tubing for performing cost-effective stimulations on complex subsea wells.
Successful entry to the region was highly dependent upon the integrated nature of the service. Access to the service providers global network permitted a high degree of influence upon the ultimate performance of the stimulation. Examples include the PIF results achieved and the responsive actions taken to remedy offshore challenges such as reservoir lock-up on well #3.
One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit. Occasionally, small amounts of hydrocarbons are added to water-based mud to reduce friction on the drillpipe.
Thin oil columns overlain by free gas and underlain by water pose difficult problems in well spacing and completion method, production policy, and reserves estimation. In this context, "thin" is a relative term. Whether an oil column is considered thin depends on costs to drill and produce the accumulation. For example, in the Bream field (Australia Bass Strait, 230 ft water depth), 44 ft was considered thin, whereas in the Troll field (offshore Norway, 980 ft water depth), 79 ft was considered thin. Onshore U.S.A., 20 ft is considered thin. Irrgang takes a pragmatic approach, defining thin oil columns as those that "will cone both water and gas when produced at commercial rates."
The term "geopressure," introduced in the late 1950s by Charles Stuart of Shell Oil Co., refers to reservoir fluid pressure that significantly exceeds hydrostatic pressure (which is 0.4 to 0.5 psi/ft of depth), possibly approaching overburden pressure (approximately 1.0 psi/ft). Geopressured accumulations have been observed in many areas of the world. In regressive tertiary basins (the geologic setting for most geopressured accumulations), such pressures in sand/shale sequences generally are attributed to undercompaction of thick sequences of marine shales. Reservoirs in this depositional sequence tend to be geologically complex and exhibit producing mechanisms that are not well understood. Both of these factors cause considerable uncertainty in reserves estimates at all stages of development/production and reservoir maturity.
Compressibility is the volume change of a material when pressure is applied. When water is produced, the pressure changes from reservoir pressure, affecting the volume of produced water. Understanding the compressibility of formation water is also important to the understanding of volumes of oil, gas, and water in the reservoir rock. The compressibility of formation water at pressures above the bubblepoint is defined as the change in water volume per unit water volume per psi change in pressure. Water compressibility also depends on the salinity.
Phase behavior describes the complex interaction between physically distinct, separable portions of matter called phases that are in contact with each other. Typical phases are solids, liquids and vapors. Thermodynamics, which is central to understanding phase behavior, is the study of energy and its transformations. Using thermodynamics, we can follow the energy changes that occur during phase changes and predict the outcome of a process. Thermodynamics began as the study of heat applied to steam power but was substantially broadened by Gibbs in the middle to late 1800s.
As defined by the U.S. Federal Energy Regulatory Commission (U.S. FERC), low-permeability ("tight") gas reservoirs have an average in-situ permeability of 0.1 md or less. Others have placed the upper limit at 1 md. Estimates of ultimate recovery from these resources vary widely and depend chiefly on assumptions of wellhead gas price. Methods for estimating gas reserves in moderate- to high-permeability reservoirs are unreliable in very-low-permeability reservoirs. The unreliability can be attributed to the geologic setting in which these reservoirs occur and the completion methods required to make them commercial.
Solar enhanced oil recovery, or solar EOR, is a form of thermal enhanced oil recovery (EOR), a technique applied by oil producers to extract more oil from maturing oil fields. Solar EOR uses CSP to use the sun's energy to heat water and generate steam. The steam is injected into an oil reservoir to reduce the viscosity, or thin, heavy crude thus facilitating its flow to the surface. Thermal recovery processes, also known as steam injection, have traditionally burned natural gas to produce steam. Solar EOR is proving to be a viable alternative to gas-fired steam production for the oil industry.
In-situ combustion requires standard field equipment for oil production, but with particular attention to air compression, ignition, well design, completion, and production practices. Air-compression systems are critical to the success of any in-situ combustion field project. Past failures often can be traced to poor compressor design, faulty maintenance, or operating mistakes. See Compressors for a detailed discussion of compressors and sizing considerations. Other discussions are available in Sarathi.
Many useful and reasonably accurate calculations can be made on in-situ combustion to predict the behavior of a proposed project. This page discusses the calculation process involved with behavior prediction. In-situ combustion prediction calculations will be explained in the following diagrams and example calculations. They start with a very simple heat balance and are then extended to more closely represent what happens in the reservoir. Start by assuming that no combustion data are available to get an initial idea of the feasibility of a project.