Flow assurance

Flow assurance requires a multidisciplinary approach and is key to production system operability.

Flow assurance is becoming increasing important in the operability oil/gas production, especially in deepwater. This picture is a large gas hydrate plug formed in a Petrobras subsea hydrocarbon pipeline.

Flow assurance refers to succesfully maintaining sustained hydrocarbon production by properly managing the flow (oil, gas, and water) without slugging or restricts/blockages due to undesired phase changes. The term originally covered the thermal hydraulic analysis and evaluation of potential production problems associated with solids formation, such as waxes, asphaltenes, hydrates and scale. Now, it has a much broader definition and includes all issues important to maintaining the flow of oil and gas from reservoir to reception facilities (onshore and offshore). The flow assurance paradigm currently is shifting from avoidance to risk management

Introduction

A typical black oil flow assurance phase diagram in GoM.

In its virgin reservoir state, the hydrocarbon and formation water are in equilibrium with its environment for millions of years. During production, this equilibrium is abruptly disturbed as the hydrocarbon and water flow out of the reservoir into the production system. As the fluids try to reach new equilibrium with the changing environments, phase changes will likely occur, for example, gas breaking out from oil, liquid hydrocarbon condensing from gas, solids forming in the hydrocarbon or produced water phases, etc. A typical flow assurance diagram of a black oil is included to the right. These phenomena pose threat to smooth operation of the production facilities. Flow assurance is about understanding these threats and develop the appropriate engineering, design, and chemical methods to combat or remediate them.

Why is Flow Assurance Important?

Flow assurance is essential to the sustained operability of production facilities. Flow assurance failures often result in production shut-down and costly interventions. What operating environments does flow assurance typically pose a challenge? Almost all, but some are worse than others. Indeed, when Petrobras introduced "Garantia de Fluxo", it was intended for deepwater developments, which often have high pressure and low temperature conditions. The high capital costs and restricted accessibility of deepwater facilities and flowlines made it critical to understand and prevent the various phenomena that could hamper production, particularly hydrates and multiphase flow phenomena. With the move to ever increasing water depths, the flow assurance challenges have only amplified. Another area that flow assurance plays a critical role is arctic environments, such as Sakhalin, Alaska, etc. In these environments, temperatures can be much lower than the oil and water freezing points.

As "easy oil" is running out and production is moving into more challenging environments, the importance of flow assurance will become more and more pronounced.

Flow Assurance Workflow Process

Flow assurance workflow process with surveillance incorporated.

Flow assurance studies are fundamental to the development of oil and gas discoveries, especially in deep water. In all cases, integrated flow assurance analysis is a key driver of field development, from reservoir to export system and must be addressed early in the design process for offshore production systems. Flow assurance risk assessment includes:

• Interface with other disciplines, from reservoir engineering to topsides.
• Solids prediction and management: gas hydrates, asphaltenes, wax, scale, and naphthenates, etc.
• Transient or static multiphase thermal hydraulic simulation ( P, T profiles, slugging, etc.)

A typical flow assurance workflow scheme is included in the figure to the right.

1. The process starts in the exploration and appraisal phase where both in-situ fluid property data are measured and selected fluid samples are retrieved for more detailed laboratory analysis.
2. Specific flow assurance related studies may be run on the fluid samples in the laboratory. The scope and type of these analyses will depend on the anticipated problems.
3. The laboratory data is then used in a series of engineering software tools to model various scenarios for the production system.
4. From that process, each system and its appropriate flow assurance management strategy is defined.
5. Once the selected system is designed and installed, the flow assurance management processes should be monitored and optimized. Recognizing that the initial design of these strategies was most likely conservative there is typically good opportunities to optimize the process and reduce OPEX. However, the large cost of failure requires a careful monitoring of the system to catch potential problems before they result in a catastrophic failure like a blocked flowline.
6. In surveillance, system data like temperatures, pressures and flow rates are collected from sensors at various points. Models that used fluid property data obtained in the design phase are conditioned to the measured system data. These models can now be used to determine the current state of the system and to optimize the system through a series of what if runs.

Fluid sampling

Schematic diagram of downhole sampling tool for acquiring crude oil samples and performing optical spectral chemical analysis in situ. The tool is used in the open hole just after the well is drilled and prior to casing the well. The probe is pressed firmly against the borehole wall to make hydraulic communication with permeable zones in the oil well to extract formation fluids.

The composition and character of reservoir hydrocarbons and formation water are fundamental to oil and gas economics. Fluid properties are directly input into deepwater project development assessment, production system design, development and operating costs and reserve assignment. Wide variations in fluid properties can occur not only on a regional scale, but between multiple stacked pay zones within single wells and even within single continuously communicating reservoirs. Whenever possible, samples from multiple depths or aerial positions should be considered to identify and quantify variations. Understanding the magnitude and nature of compositional variation is important for system design.

In order to take samples downhole, a sampling device, usually a cylindrical instrument is lowered either by wire-line, pipe, or as part of the drill-string in a welltest. Down-hole sampling can be conducted in either an open or cased hole. Various devices have been developed to subsequently take samples and equipment varies from company to company. Sample cylinders are either standard piston or single phase.

During appraisal, the goal of the downhole sampling procedure is to bring a sample back to the lab that is identical in composition to the fluid in the reservoir. Unfortunately, changes in pressure and temperature can cause phase changes that lead to sample alteration. If phase change does occur, it is important to minimize the time the sample remains in the multi-phase condition and avoid sample transfers. If a sample must be moved between vessels, it must be carefully equilibrated at reservoir conditions prior to transfer. Pressures, temperatures, validation data, transfers and volumes need to be documented. Introduction of contaminates during the sample acquisition process can also alter the fluid composition. The most common source of contamination is from drilling fluids.

Asphaltene measurements place the most stringent demand on hydrocarbon sample quality. Asphaltene is easily precipitated and lost during pressure and temperature reductions encountered during sampling. The stability of asphaltenes are also greatly effected by the presence of contaminates. If sampling for special analyses, such as H₂S and mercury, special sampling procedures and containers are often required.

Lab analysis

PVT Analysis

PVT information is crucial for understanding the flow behaviour of the production fluids and it is key to both flow assurance and reservoir modelling. Under reservoir condition, the hydrocarbon fluid is typically a homogeneous single phase. As the fluids are produced and pressure and temperature change, the fluid may split into different phases, particularly liquid and gas phases. It is of utmost importance to know and understand how much liquid and gas phase will be produced and what the compositions and properties are. This description is called the PVT (Pressure, Volume, Temperature) behavior of the fluid.

PVT analysis typically includes reservoir composition, single or multi-stage flash, flashed gas and oil compositions, GOR, gas and oil gravity, viscosity under reservoir conditions, bubble points, etc.

Water composition

Proper water composition analysis is critical to hydrate and scale risk assessments. Typical cation components are typically easy to analyze with ICP, but great care must be taken for bicarbonate and sulphate analyses, both of which are prone to error and key to scale assessment.

Flow assurance property characterization

The list of relevant fluid properties will vary depending on the type of fluid and the expected system operating conditions.

• For wax, the following are measured on a dead oil: the normal paraffin distribution, using high temperature gas chromatography (HTGC), wax appearance temperature, viscosity and pour point. If these parameters indicate potential wax deposition, elevated viscosity or gelling problems, a more thorough analysis program including measurements made under live oil line conditions and chemical evaluation is needed.

• For asphaltenes, dead oil characterization data including SARA (Saturate Aromatic Resin Asphaltene) and paraffinic solvent (typically n-pentane or n-heptane) titration endpoint are used as screens for fluid stability. Because asphaltene screening and modeling capability is less well developed than those for wax, it is common to measure at least one live oil asphaltene precipitation pressure as well. If an asphaltene issue is identified, additional studies are defined to map out the Asphaltene phase diagram as a function of temperature and to evaluate the effectiveness of chemicals or coatings as prevention strategies.

• For gas hydrates, composition from a standard PVT or validation study and produced water composition are used in a thermodynamic model to generate the expected hydrate formation boundary. If the compositional data are unusual or the pressure and temperature conditions are outside the range of validity of the model, direct measurement of hydrate formation conditions may be performed. If hydrate formation is a potential risk to the production system, a combination of modelling and experimental tests with representative fluids are conducted to evaluate the performance of thermodynamic inhibitors and/or low dosage hydrate inhibitors (LDHI) (which includes both kinetic hydrate inhibitors and anti-agglomerants).

• For inorganic scales, formation water compositions are used to evaluate scaling potential in various production scenarios. As the measured water composition may not be representative of its composition under reservoir condition because some solids may have dropped out during the sampling and measurement process, it is important to reconstitute its reservoir composition based on the field specific petrophysical rock properties. If scaling risk indicated, capillary tube blocking test can be conducted to evaluate the risk experimentally and screen for scale inhibitors that work for this fluid.

Previous research indicated that these potential solid deposits can influence each others' behavior, it is important to take that into consideration during flow assurance property characterization and chemical selection.

Thermal hydraulic modelling

Thermal hydraulic analysis is key to the overall system design and operation. It incorporates all the relevant information, such as fluid composition, system components and dimension, topography, etc. to give the overall picture of what the production will look like.

Steady state analysis

Steady state analysis is done for system during normal operation, typically with tools such as PIPESIM or UNISIM. It gives the flowing pressure and temperature profiles during steady state with different production rates and system designs. Results from the steady state analysis help narrow down the design options and specifications and what additional steps need to be taken to ensure smooth operation. For example, decisions on flowline size and pressure rating, tree pressure and temperature rating, choke location, and thermal insulation requirements partially come from the steady state analysis.

Transient analysis

Transient analysis is to study how the system behave during start-up and shut-down operations. It is typically done with OLGA. Key outcomes from the transient analysis include cool down time, warm up time, slugging, chilly choke effect, hot oil circulation, etc.

Flow Assurance Strategy

Flow assurance strategy is fundamentally about system operability, which is about how to design and operate the system to avoid and mitigate all the relevant flow assurance risks.

System design

System designs for flow assurance consideration are typically (or should be) incorporated during early stage of the project, which include subsea layout, flowline sizing and insulation, flowline burial, pigging loop, hot oiling capability, chemical delivery requirement, separator sizing, choke location, riser base gas lift, etc. If these considerations are integrated into the system design, operators will have a much easier time managing flow assurance risks once the system comes online.

Operation

This part involves what operational procedures the operators should follow to manage flow assurance risks. For example, the production may need to be maintained at certain rate, beyond which slugging becomes a severe problem. Other instances include when to conduct flowline blowdown or dead oil displacement after shut down, how the wells should be ramped up during startup to avoid hydrate blockage, hot-oiling to warm up the flowline, flow diversion/combination to avoid slugging, etc.

Chemicals

Chemicals are typically available to mitigate/remediate almost all solid deposits, but may be with varied efficiencies. For example, asphaltene inhibitor and paraffin inhibitor are not expected to be 100% (in fact, 50-60% is more reasonable) effective in preventing solid buildup. On the other hand, thermal dynamic hydrate inhibitors can provide full protection against hydrate formation if dosed at the recommended rate.

For any chemical strategy, the following are important considerations:

• Performance evaluation has to be representative to field conditions.
• Injection point is ideally upstream of the expected trouble spot.
• Deliverability
• They don't inadvertently cause other negative consequences.
• Compatibility, including chemical-chemical, chemical-production fluid, chemical-material compatibilities.

Flow Assurance Remediation Strategy

Flow assurance remediation strategy can be designed into the system early on, for example, a mechanism to deliver solvents into the well or flowline, methods for flowline depressurization.

If deposits/blockages do occur, depending on the types of solids,

• chemical solvents can be used to dissolve or loosen the deposits
• temperature can be raised to melt the solids if they are wax or hydrate, through either local external heating or hot oiling
• depressurization to dissociate hydrates
• mechanical intervention and scrapping