High Bottom Hole Pressure Research Articles

Effects of non-equilibrium phase behavior in nanopores on multi-component transport during CO2 injection into shale oil reservoir

Injecting CO2 into shale oil reservoirs is one of the most effective methods for enhancing oil recovery (EOR) while simultaneously facilitating CO2 capture, utilization, and storage (CCUS). However, it is not always that gas dissolution or condensate evaporation reaches equilibrium instantaneously during the CO2 injection process. In cases where equilibrium is not attained instantaneously, conventional vapor-liquid equilibrium models will have certain limitations in characterizing phase transition hysteresis. These limitations will affect the accuracy of simulating multi-component transport in porous media. In this paper, a robust and generic vapor-liquid non-equilibrium thermodynamic model considering nano-confinement effects (NC) was established by introducing component mass transfer rates proportional to the chemical potential difference. The established model was then used to modify the fully-compositional, projection-based embedded discrete fracture model (pEDFM). Furthermore, C++ hybrid programming and the Graphics Processing Unit (GPU) parallel method were both used to accelerate both the nonlinear and linear solvers. By comparing with results from MATLAB Reservoir Simulation Tools (MRST), Eclipse, and tNavigator, the accuracy and advantages of our solver were demonstrated. The results show that if the underground fluid undergoes a phase transition from a vapor-liquid two-phase state to a single-phase state, non-equilibrium thermodynamic effects need to be considered, and the simulation results show a larger two-phase zone, higher bottom hole pressure, and lower cumulative liquid production. But the nano-confinement effects will weaken the non-equilibrium thermodynamic effects.

Geomechanical risk assessment for CO2 storage in deep saline aquifers

We study CO2 injection into a saline aquifer intersected by a tectonic fault using a coupled modeling approach to evaluate potential geomechanical risks. The simulation approach integrates the reservoir and mechanical simulators through a data transfer algorithm. MUFITS simulates non-isothermal multiphase flow in the reservoir, while FLAC3D calculates its mechanical equilibrium state. We accurately describe the tectonic fault, which consists of damage and core zones, and derive novel analytical closure relations governing the permeability alteration in the fault zone. We estimate the permeability of the activated fracture network in the damage zone and calculate the permeability of the main crack in the fault core, which opens on asperities due to slip. The coupled model is applied to simulate CO2 injection into synthetic and realistic reservoirs. In the synthetic reservoir model, we examine the impact of formation depth and initial tectonic stresses on geomechanical risks. Pronounced tectonic stresses lead to inelastic deformations in the fault zone. Regardless of the magnitude of tectonic stress, slip along the fault plane occurs, and the main crack in the fault core opens on asperities, causing CO2 leakage out of the storage aquifer. In the realistic reservoir model, we demonstrate that sufficiently high bottomhole pressure induces plastic deformations in the near-wellbore zone, interpreted as rock fracturing, without slippage along the fault plane. We perform a sensitivity analysis of the coupled model, varying the mechanical and flow properties of the storage layers and fault zone to assess fault stability and associated geomechanical risks.

A Novel Equivalent Numerical Simulation Method for Non-Darcy Seepage Flow in Low-Permeability Reservoirs

The low permeability and submicron throats in most shale or tight sandstone reservoirs have a significant impact on microscale flow. The flow characteristics can be described with difficultly by the conventional Darcy flow in low-permeability reservoirs. In particular, the thickness of the boundary layer is an important factor affecting the formation permeability, and the relative permeability curve obtained under conventional conditions cannot accurately express the seepage characteristics of porous media. In this work, the apparent permeability and relative permeability were calculated by using non-Darcy-flow mathematical modeling. The results revealed that the newly calculated oil–water relative permeability was slightly higher than that calculated by the Darcy seepage model. The results of the non-Darcy flow based on the conceptual model showed that the area swept by water in non-Darcy was smaller than that in Darcy seepage. The fingering phenomenon and the high bottom hole pressure in the non-Darcy seepage model resulted from the larger amount of injected water. There was a large pressure difference between the injection and production wells where the permeability changed greatly. A small pressure difference between wells resulted in lower variation of permeability. Consequently, the non-Darcy simulation results were consistent with actual production data.

Numerical simulation on the multiple planar fracture propagation with perforation plugging in horizontal wells

Intra-stage multi-cluster temporary plugging and diverting fracturing (ITPF) is one of the fastest-growing techniques to obtain uniform reservoir stimulation in shale gas reservoirs. However, propagation geometries of multiple fractures during ITPF are not clear due that the existing numerical models cannot capture the effects of perforation plugging. In this paper, a new three-dimensional FEM based on CZM was developed to investigate multiple planar fracture propagation considering perforation plugging during ITPF. Meanwhile, the fluid pipe element and its subroutine were first developed to realize the flux partitioning before or after perforation plugging. The results showed that the perforation plugging changed the original distribution of the number of perforations in each fracture, thus changing the flux partitioning after perforation plugging, which could eliminate the effect of stress interference between multiple fractures and promote a uniform fluid distribution. The standard deviation of fluid distribution in the perforation plugging case was only 8.48% of that in the non-diversion case. Furthermore, critical plugging parameters have been investigated quantitatively. Specifically, injecting more diverters will create a higher fluid pressure rise in the wellbore, which will increase the risk of wellbore integrity. Comprehensively considering pressure rise and fluid distribution, the number of diverters should be 50% of the total number of perforations ( N pt ), whose standard deviation of fluid distribution of multiple fractures was lower than those in the cases of injecting 10% N pt , 30% N pt and 70% N pt . The diverters should be injected at an appropriate timing, i.e. 40% or 50% of the total fracturing time ( t ft ), whose standard deviation of the fluid distribution was only about 20% of standard deviations in the cases of injecting at 20% t ft or 70% t ft . A single injection with all diverters can maintain high bottom-hole pressure for a longer period and promote a more uniform fluid distribution. The standard deviation of the fluid distribution in the case of a single injection was 43.62%–55.41% of the other cases with multiple injection times. This study provides a meaningful perspective and some optimal plugging parameters on the field design during IPTF.

Modeling analysis of the temperature profile and trapped annular pressure induced by thermal-expanded liquid in a deep gas well

The trapped annular pressure (TAP) caused by thermal expansion is one of the serious challenges for the safe production of a deep gas well. Therefore, this article proposes a model to calculate the temperature profile of the deep gas well based on the heat transfer process and the gas properties. With the help of the temperature model, the TAP in the tubing–casing annulus is analyzed according to the annular fluid distribution and the volume consistence law. The results indicate that the temperature inside the tubing string decreases faster under higher bottom hole pressure. When the tubing–casing annulus is totally filled with the annular protection liquid, the TAP continues increasing with the production rate. Considering the high production rate, the TAP is inevitable and high enough to damage the integrity of the deep gas well. The nitrogen gas mitigates the TAP by reducing the annular liquid volume and providing the extra space to accommodate the thermal-expanded annular liquid. A good mitigation performance can be achieved no matter how large the production rate is. The mitigation performance can be divided into the fast-decreasing stage, the efficient control stage, and the stable stage. These three stages occur as the nitrogen gas column length increases. The compression of the nitrogen gas volume plays a major role in the fast decrease stage while the reduction of the annular liquid plays a major role in the stable stage. For the best cost-effectiveness, the nitrogen gas column is recommended in the efficient control stage and should not exceed 15%.

Production performance of the low-permeability reservoirs: Impact of contamination at the wellbore vicinity

Hydrocarbon reservoirs with low porosity and permeability are usually vulnerable to be contaminated owing to the drilling and completion fluids-induced formation damage, which significantly impedes the efficient production of hydrocarbon. However, most current productivity prediction models introduce the concept of skin factor to capture the near-wellbore contamination, which only considers the change of permeability before and after contamination, whereas neglecting the change of threshold pressure gradient (TPG) affected by the permeability reduction. Also, few works have been done to focus on the influences of contamination, TPG, sensitivity of rock porosity to internal stress, and fluid compressibility simultaneously in the actual production process of the low-permeability reservoir. Therefore, to bridge the knowledge gap, this study presents a new comprehensive productivity model encompassing those multiple influencing factors. Firstly, the seepage area is divided into contaminated zone and uncontaminated zone. Thereafter, the proposed model is established based on non-Darcy seepage theory and continuity principle, comprehensively taking account of the effects of different permeability and TPG between contaminated zone and uncontaminated zone, stress sensitivity based on primary stress in porous media, and the fluid compressibility. Subsequently, the newly proposed model is proved to be reliable through the consistency between the simplified model and the existing models in the literatures. Finally, the sensitivity analysis is employed to investigate the effects of key parameters. Main results show that a) the decreased permeability affected by contamination would result in increased TPG, further lowering the well productivity. b) Contamination, TPG and stress sensitivity will cause additional pressure drop and production loss, which will overestimate the production rate by neglecting them. While the fluid compressibility could boost the well productivity, which will underestimate the production rate by ignoring it. c) The order of productivity influencing factors is contamination > TPG > the fluid compressibility > stress sensitivity. d) Contamination and the TPG are significant influencing factors at stage of high bottomhole pressure. Moreover, the influence degree of contamination, the fluid compressibility and stress sensitivity gradually increase, while the influence degree of the TPG greatly decreases with lower pressure.

Investigation of the cutting force response to a PDC cutter in rock using the discrete element method

In the drilling industry, Polycrystalline Diamond Compact (PDC) bits with multiple fixed PDC cutters are widely applied to cut rock under high bottom hole pressure and high temperature. The bit-rock interaction is the main excitation source of drill string vibrations and needs to be understood and controlled better to improve the performance of the drilling process. Rock cutting mechanisms can be examined best for a single PDC cutter: Limitations of dynamic control and available sensors in experimental setups are eliminated in numerical simulations. Using the Discrete Element Method (DEM), deformation and strength of rock can be modeled through its full degradation in the PDC cutting process under typical environmental conditions. Stresses and strains in the rock material and on the cutter faces become available for examination.In this paper, numerical simulations of the cutting process are conducted using a modified bonded-particle model (specialized DEM), which is calibrated to a pressure series of high-strain triaxial laboratory tests. The simulation results are interpreted from the perspective of continuum mechanics providing stress and strain rate fields within the rock. These serve to identify two primary deformation modes predominant in two distinct zones moving with the PDC cutter: A crush zone below the chamfer and a shear zone ahead of the cutter face. The influences of two cutter design parameters, the back rake angle and the chamfer size, on these zones and the cutting force, are investigated. The shear angle is found to decrease with increasing back rake angle, resulting in a wider shear band. Moreover, the back rake angle has a considerable influence on the cutting forces both in the normal and tangential direction, whereas the chamfer size affects the normal cutting force predominantly. These results are in good accordance with experimental observations in the literature. Furthermore, the relationship between the cutting force and underlying rock failure mechanisms is clarified.This study enhances the understanding of the rock cutting process and gives first indications for dynamic cutting force control through cutter design.

Adaptive analysis of multistage down-hole throttling and optimization design of process parameters in Sulige gas field

The Sulige Gas Field mainly adopts down-hole throttling production technology. For gas Wells with high bottom-hole pressure and productivity and low pressure drop in the testing process, it is difficult to reduce the wellhead pressure to the ideal value by installing a single-stage down-hole throttle, which cannot meet the needs of existing middle and low-pressure gas gathering technology in Sulige Gas field. Therefore, it is proposed to adopt down-hole multi-stage throttling technology, which not only makes full use of the residual pressure and heat of the well bore, but also ensures the safety of the surface gathering and transportation process system and the normal production of gas wells. In this paper, the optimization design method and theory for the technological parameters of the down-hole multi-stage throttling system of gas wells are established. According to the constraint of low-pressure gas collection mode in a temperature and pressure of wellhead safety to determine the number of down-hole choke and the process parameters. Discuss the applied conditions of down-hole multi-stage throttling, and provide theoretical support for the selection of the down-hole choke technology of the Sulige gas well and the safe and stable production of the gas well. It has important guiding significance for gas field quality and efficiency improvement and fine management.

Stress sensitivity evaluation of ultra-low permeability sandstone reservoir and its influence on oilfield development

Luohe ultra-low permeability sandstone reservoir is a hot block in Yanchang oilfield, which is a potential point for increasing production and reservoir. In view of the current situation that there is no unified stress sensitivity evaluation standard for ultra-low permeability sandstone in the study area, taking the ultra-low permeability sandstone in Luohe district as the research object, the stress sensitivity evaluation of ultra-low permeability sandstone is carried out by using experimental analysis as the main means. The results show that it is more accurate to evaluate porosity by using pore stress sensitivity coefficient instead of pore compressibility coefficient. With the increase of net overburden pressure, the porosity stress sensitivity decreases gradually; the permeability stress sensitivity is evaluated by variable confining pressure. With the increase of confining pressure, the permeability damage decreases. With the decrease of confining pressure, the permeability damage increases, but it can not recover to the original value, so the permeability damage is irreversible; in the low bottom hole pressure stage, stress sensitivity has a greater impact on oil well productivity, while in the high bottom hole pressure stage, stress sensitivity has a smaller impact on oil well productivity; advanced water injection can reduce the adverse effect of stress sensitivity on the development of ultra-low permeability sandstone and maximize the economic benefits. The research results clarify the method of stress sensitivity evaluation, and provide guidance for efficient water injection in the next step.

Decomposition prevention through thermal sensitivity of hydrate formations around wellbore

The traditional drilling engineering research on wellbore stability of hydrate formation neglects the interactions between heat transfer and mass transfer, a new multi-field coupling model is established to study the effects, and this model considers hydrate kinetic decomposition rate in different salinities, two-phase flows and heat transfer in pores. The calculation results show most of engineering parameters affects hydrate decomposition through high thermal sensitivity of hydrate formations: The direction and value of seepage will change the temperature field and the position of hydrate dissociation front. High bottomhole pressure will bring in the radial seepage, increasing formation temperature and exacerbating hydrate decomposition. The latent heat of hydrate dissociation reduces temperature growth in the entire formation, inhibits the decomposition front advancement and decreases the decomposition rate. Reducing the bottomhole temperature can get an incremental margin for wellbore stability. High salinity in drilling fluid will provide negative impact under high bottomhole pressure and high permeability. These results show the protection of hydrate formations should avoid increasing the density of drilling fluid and focus on cooling drilling fluid and reducing drilling time.

The threshold pressure gradient effect in the tight sandstone gas reservoirs with high water saturation

From research and field development, the threshold pressure gradient (TPG) in tight formations is required before the fluid starts to flow. This paper addresses the different factors that affect the TPG in tight sandstone gas reservoirs with high water saturation. First and foremost, the petrophysical properties were obtained through the following tests: X ray diffraction, scanning electron microscope and nuclear magnetic resonance using cores from Sulige gas field in China. Secondly, the TPG experimental investigations were performed using air bubble method, and a TPG correlation was obtained considering the influences of permeability, connate water and movable water. Finally, a gas production model was established with the TPG, slip and diffusion effects taken into account, and its applications were discussed using actual reservoir parameters. The results showed that the cores have plenty of clay minerals and high connate water saturation. Besides, the throat radii from NMR mainly are distributed between 0.0004 and 0.1 µm, with a few between 0.1 and 0.4 µm. The clay depositions decrease the pore and throat diameters, which result in Jamin effect. The experimental results showed that the TPG exists at the connate water saturation, and increase exponentially with either an increase in dimensionless water saturation or decrease in permeability. The IPR curves showed the TPG effect on gas production is very serious i.e. production loss degree decreases especially at high bottom hole pressure, and the production loss degree decreases as the bottom hole pressure decreases. The greater the water saturation or the smaller the permeability, the greater the production loss degree. In addition, the TPG affects the intercept of the abscissa of the flow curve, and the slope of the curve decreases as water saturation increases.

Experimental investigations on energy recovery from water-saturated hydrate bearing sediments via depressurization approach

A huge amount of natural gas hydrates remains untapped in permafrost and continental margin. While several short term field production tests have been carried out, the underlying challenges during hydrate dissociation in porous media, such as the interdependent production behavior of gas and water, is still not well understood. In this work, we employed depressurization technique to recover natural gas from a water saturated hydrate bearing sediment (40% SH, 50% SA and 10% SG) at 281.5K surrounding temperature. During depressurization, the bottom hole pressure (BHP) was maintained at constant pressures of 5.0, 4.0, 3.0 and 2.1MPa respectively to evaluate its effect on gas and water production. As expected, a higher BHP (corresponding to a lower dissociation driving force) resulted in a slower gas and water production. At a BHP of 2.1MPa, thermal buffering was observed below ice point (272.7K), accompanied by enhanced gas production. By lowering BHP from 5.0MPa to 2.1MPa, the percentage methane produced increased from 45.5% to 83.0%; whereas the cumulative water production decreased from 217mL to 157mL. The difference in gas and water production was attributed to the preferential production of aqueous phase at higher BHPs (5.0 and 4.0MPa) nearing the end of hydrate dissociation whereby less hydrates were present.

The numerical simulation of thermal recovery based on hydraulic fracture heating technology in shale gas reservoir

Shale gas reservoirs have received considerable attention for their potential in satisfying future energy demands. Technical advances in horizontal well drilling and hydraulic fracturing have paved the way for the development of shale gas reservoirs. Compared with conventional gas reservoir, adsorbed gas accounts for a large proportion of total gas within shale, so the amount of gas desorbed from the formation has a large impact on the ultimate gas recovery. Recently, efforts toward the thermal recovery of shale oil based on hydraulic fracture heating technology (ExxonMobil's Electrofrac) have made some progress. However, the temperature-dependent adsorption behavior and its major applications of evaluating thermal stimulation as a recovery method have not been thoroughly explored. Additionally, many complicated nonlinear processes coexist in shale formation such as Knudsen diffusion, the pressure dependent phenomenon and non-Darcy flow, presenting a significant challenge for quantifying flow in shale gas reservoir.To investigate the effect of thermal recovery based on hydraulic fracture heating, a fully coupled numerical model of a fractured horizontal well is developed to capture the real gas flow in shale gas reservoir. Discrete fracture, dual continuum media and single porosity media are employed to describe the hydraulic fractures, the stimulated reservoir volume (SRV) region and the matrix, respectively. The model incorporates non-linear flow mechanisms including adsorption/desorption, Knudsen diffusion, non-Darcy flow and pressure dependent phenomenon, as well as heat diffusion processes within the shale reserve. Then, the effectiveness of formation factors on thermal recovery is analyzed.The results show that hydraulic fracture heating can actually enhance shale gas recovery by altering gas desorption behavior, and that this method is more suitable for long-term production. More adsorbed gas can be recovered with increasing simulation temperature. The thermal properties of the shale formation only have limited impacts on the long-term production. The gas production rate is primarily determined by the simulation temperature, matrix adsorption ability, fracture spacing, area of the SRV region, bottom hole pressure (BHP) and reservoir permeability. A shale gas reservoir with a large Langmuir volume and SRV area, relatively small fracture spacing, and a high BHP has the potential for thermal treatment to enhance gas recovery. The fracture temperature, the area of the SRV region and the fracture spacing are the only three factors that can be controlled during the design and execution of thermal treatment in the field.

Numerical Simulation of Stress Change during Wellbore Injection

The important matter during any process in the well is wellbore integrity. Regarding to the geomechanics of the well, high bottom-hole pressure and low temperature could lead to the fracturing. The stress near the wellbore is a function of the flow and temperature, and it precisely determined to avoid the wellbore failure. The objective of this paper is to simulate stress change in the well for the injection. In order to analyze the stress in the wellbore a finite volume analysis has done for the wellbore. The stress equation relates to flow equation with the equation of principle stress. It means that the pressure is a key parameter for determination of the stress. The procedure which has to be followed is transforming the equations to weak form, meshing the defined shape and programing to obtain the values for each node. The result for the stress is obtained for some meshed bodies. The accuracy enhanced by choosing smaller mesh sizing.

Unique Multistage Process Allows Pinpoint Treatment of Hard-to-Reach Pay

Summary Perforating multiple-pay intervals to achieve optimum treatment coverage has long been a topic of considerable debate. Perforation selection can play a crucial role in well performance. The consequences of inadequate perforation coverage can compromise fracture optimization, limit production, result in missed pay, and limit reservoir access. Multizone-fracture treatments have been performed in the past with a variety of methods ranging from limited entry to mechanical isolation with bridge plug and packer. These and other techniques routinely have been applied to stimulate discrete intervals within a formation in an attempt to maximize the production of discrete-pay zones or stringers. One method consists of perforating and isolating each zone, then performing the stimulation treatment. Wireline is used to isolate the previous zone and perforate the next stage. The treatment of multiple intervals in this manner can be a costly and time-consuming process. A new multistage treatment process optimizes perforation and treatment design. This technique, known as "external casing perforating" (EXCP) allows the operator to perforate and isolate individual zones in as little as 5 minutes between treatment stages. As many as 17 discrete intervals have been treated within a 24-hour period. Moreover, this approach minimizes total-treatment volume by using the flush from the previous stage as the pad on the next stage, thus placing less fluid on the formation. The time to first sales has been reduced from days to a matter of hours by eliminating bridge-plug isolation and costly post-job cleanup. Production from multiple horizons may be brought online quickly in one rigless operation without damaging and time-consuming shut-ins. This paper describes the perforating and stimulation technique and quantifies cost savings to the operator associated with the reduced volumes and time saving. Additional benefits, such as reductions in friction pressure and polymer damage, and means for fracture optimization also will be discussed. Introduction In common practice, economic factors dictate pay selection in a given wellbore. In multizone completions, difficult choices must be made when determing whether to sacrifice optimum zonal coverage or to selectively isolate and stimulate discrete-pay intervals or stringers. In the selection process, productive intervals may be sacrificed or left behind because of economic considerations. In some cases, these zones have gone unproduced for years. These intervals could represent access to several hundred feet of idle reserves. Two such intervals were discovered in the Wilshire Devonian field in west Texas. During fracture stimulation, it became evident that part of one interval had substantially higher bottomhole pressure than the adjacent zones, making it more challenging to stimulate with limited-entry techniques (Lagrone et al. 1963). A post-job-tracer survey documented results from an attempt at limited entry where the middle zone was left unstimulated (Fig. 1). Previously, 3D fracture simulators indicated that the zones would fuse in a single fracture. Once an aggressive stimulation program was initiated, the higher pressures were verified by production logs and bottomhole-pressure tests. Bottomhole pressure, a key component in stress calculation, proved to be a key factor in zonal isolation and effectively stimulating these zones. The main consideration is pay identification for optimal-treatment coverage. In many cases, criteria for productive intervals must be redefined on the basis of in-field test analyses and, ultimately, production. What was once considered a nonproductive interval might prove economic in the future, especially as petroleum pricing drives the technology necessary to extract hard-to-reach reserves. Advances in log analysis, computer modeling, and 3D seismic surveys have further enhanced the industry's ability to rapidly identify and evaluate potential pay intervals (Mendoza 1996; Davies et al. 1994; Warpinski et al. 1995). Operators surveyed by the Gas Research Inst. (GRI) in the mid-1990s recognized opportunities for future improvements in production rates and cost reduction through the use of these new technologies (Penny and Conway 1996). The initial completion on a well can have an enormous impact on the ability to effectively access and produce the entire reservoir. After completion, it may not be practical to reenter a wellbore to reacquire missed pay. An optimized completion process is less costly and far more efficient during the initial completion. Any net gain in reserves must be weighed against completion cost. In many cases, risk associated with the initial completion may persuade an operator to resist technology that may provide optimum production and reservoir access. Technology often requires some initial risk and diligence in new applications to justify a project. The EXCP completion process is no exception, especially because most of the cost is incurred during drilling. Most drilling departments are driven to reduce cost and may not realize the potential of the EXCP process to reduce final completion cost, reduce formation damage, and increase booked reserves.

Enhanced Hydrate Inhibition in an Alberta Gas Field

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90422, "Enhanced Hydrate Inhibition in Alberta Gas Field," by Dana Budd, EnCana Corp., and Danica Hurd, SPE, Marek Pakulski, SPE, and Thane D. Schaffer, SPE, BJ Chemical Services, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September. Operating gas wells in southern Alberta poses challenges. High bottomhole pressure in new wells, low bottomhole temperatures, and the Joule-Thompson expansion-cooling effect (which often lowers the gas-stream temperature below the brine freezing point) create conditions favorable for the formation of gas hydrates in wells and transportation pipelines. The problems are aggravated during cold winter months, when wells and pipelines have strong tendencies to plug with hydrates and ice. Systematic laboratory work was undertaken to explore synergistic effects between methanol and low-dosage hydrate inhibitors (LDHIs). A strong effect was discovered at a certain ratio of methanol and low-molecular-weight oligomer-type hydrate inhibitor. Introduction Gas hydrates form when water molecules crystallize around “guest” molecules. The water/guest crystallization process occurs at many combinations of temperature and pressure. Light hydrocarbons (methane to heptanes), nitrogen, carbon dioxide, and hydrogen sulfide are the guest molecules of interest to the natural-gas industry. Depending on pressure and gas composition, gas hydrates may build up at any place where water coexists with natural gas at temperatures as high as 30°C. Gas-transmission lines and new gas wells are particularly vulnerable to being blocked with hydrates. Formation of gas hydrates can be eliminated or slowed by several methods. Thermodynamic prevention methods control or eliminate elements necessary for hydrate formation: the presence of hydrate-forming guest molecules, the presence of water, high pressure, or low temperature. Eliminating any one of these four factors from a system precludes the formation of hydrates. Unfortunately, elimination of these hydrate elements is often impractical or even impossible. For long subsea transmission lines, heating and insulating is a common mechanical solution to hydrate problems. Hydrates will not form if the gas/water system is kept at a temperature greater than the hydrate-formation temperature. Gas dehydration is another method of removing a hydrate component. However, in a practical field operation, water can be economically removed only to a certain vapor pressure, and residual water vapor always exists in a dry gas. Hydrate plugs in “dry” gas lines have been reported. Adding chemicals to the gas/water streams is the most common method of preventing hydrate formation. Large amounts of alcohols, glycols, or salts are used. These additives thermodynamically destabilize hydrates and effectively lower the hydrate-formation temperature. They function by bonding to water molecules through hydrogen bonds or solvation.

How To Engineer a Fracturing Treatment

There are many causes of abnormally low well production rates, and a good engineering approach should identify them. They include low permeability, low reservoir pressure, high bottomhole pressure (BHP), high reservoir fluid viscosity, and high skin. The remainder of this paper considers the elements that can contribute to a successful hydraulic-fracture-treating program. Not all the elements need to be done in every case. However, they should be considered carefully, because they might affect both the success and the interpretation of the fracture-stimulation treatment. Inadequate evaluation could fail to identify changes and improvements to include in subsequent treatments. The following sections cover the pretreatment, execution, and evaluation phases of hydraulic fracturing. As can be appreciated, the key phase in fracture design is the pretreatment analysis.