pressure drop

In-situ gelled acids have been used for acid diversion in heterogeneous carbonate reservoirs for more than two decades. Most of the gelled systems are based on an anionic polymer that has a cleaning problem after the acid treatments that leads to formation damage. This work evaluates a new cationic-polymer acid system with the self-breaking ability for the application as an acid divergent in carbonate reservoirs.

Experimental studies have been conducted to examine the rheological properties of the polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1,000 s^-1). The impact of salinity and temperature (80 to 250°F) on the rheological properties of the acid system was also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G’) and viscous modulus (G") of the system. Single coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The impact of permeability contrast on the process of diversion was investigated by conducting dual coreflood experiments on Indiana limestone cores which had a permeability contrast of 1.5-20. CT scans were conducted to study the propagation of wormhole post acid injection for both single and dual corefloods.

The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining with temperature. For 5 wt% HCl and 20 gpt polymer content at 10 s^-1, the viscosity decreased from 230 to 40 cp with temperature increasing from 88 to 250°F. Acid spending tests demonstrated that the acid generated a gel with a significant improvement in viscosity to 260 cp (at 250°F and 10 s^-1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher permeability zone. The viscosity of gel continued to increase until it broke down to 69 cp (at 250°F and 10 s^-1) at a pH of 4.8, which provides a self-breaking system and better cleaning. Coreflood studies indicated that the wormhole and the diversion process is dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F.

The strong elastic nature of the gel (G’= 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This novel acid-polymer system has significant promise for usage in acid diversion to improve stimulation of carbonate reservoirs.

Failures due to solid particles flowing with the production fluid is one of the main causes of interventions in wells with beam pumping systems. When this problem is accompanied with chemical deposition like scale, leads to a very common intervention during well operation. This paper proposes an analytical methodology that consists of evaluation of the particle size distribution, viability for the use of sand screens and centrifugal separation systems for sand control management in wells with short run time. These systems have proven effective for failure wells that requires a sand control management system when if not addressed increase the lifting costs leading many projects to be infeasible from an economic standpoint. All the technical considerations are explained focusing on the information required and the parameters analyzed to recommend the most accurate design for sand control; selected approaches and models that have been developed to improve the run time due to sand issues are shown in this paper. A case study is showed in a well with average run time of 27 days indicating that identification of particle size distribution was a key factor to provide the right solution for sand control management. These novel applications help operators to reduced OPEX (operating expense), by minimizing well Interventions, decreasing failures in the pump; stabilizing the production and reducing the unforeseen interruption.

The objective of this paper is to present a suite of diagnostic methods and tools which have been developed to analyse and understand production performance degredation in wells lifted by ESPs in the Mangala field in Rajasthan, India. The Mangala field is one of the world’s largest full field polymer floods, currently injecting some 450kbbl/day of polymerized water, and a significant proportion of production is lifted with ESPs. With polymer breaking through to the producers, productivity and ESP performance in many wells have changed dramatically. We have observed rapidly reducing well productivity indexes (PI), changes to the pumps head/rate curve, increased inlet gas volume fraction (GVF) and reduction in the cooling efficiency of ESP motors from wellbore fluids. The main drivers for the work were to understand whether reduced well rates were a result of reduced PI or a degredation in the ESP pump curve, and whether these are purely down to polymer or combined with other factors, for example reduced reservoir pressure, increasing inlet gas, scale buildup, mechanical wear or pump recirculation.

The methodology adopted for diagnosis was broken in 5 parts – 1) Real time ESP parameter alarm system, 2) Time lapse analysis of production tubing pressure drop, 3) Time lapse analysis of pump head de-rating factor, 4) Time lapse analysis of pump and VFD horse power 5) Dead head and multi choke test data. With this workflow we were able to break down our understanding of production loss into its constituent components, namely well productivitiy, pump head/rate loss or additional tubing pressure drop. It was also possible to further make a data driven asseesment as to the most likely mechanisms leading to ESP head loss (and therefore rate loss), to be further broken own into whether this was due to polymer plugging, mechanical wear, gas volume fraction (GVF) de-rating, partial broken shaft/locked diffusers or holes/recirculation. In some cases a specific mechanism was compounded with an associated impact. For example, in ESPs equipped with an inlet screen, heavy polymer deposition over the screen was resulting in large pressure drops across the screen leading to lower head, but this also resulted in higher GVFs into first few stages of the pump, even though the GVF outside the pump were low, leading to further head loss from gas de-rating of the head curve. With knowledge of the magnitude of production losses from each of the underlying mechanisms, targeted remediation could then be planned.

The well and pump modelling adopted in the workflow utilise standard industry calculations, but the combination of these into highly integrated visual displays combined with time lapse analysis of operating performance, provide a unique solution not seen in commercial software we have screened.

The paper also provides various real field examples of ESP performance deterioration, showing the impact of polymer deposition leading to increased pump hydraulic friction losses, pump mechanical failure and high motor winding temperature. Diagnoses based on the presented workflow have in many cases been verified by inspection reports on failed ESPs. Diagnosis on ESPs that have not failed cannot be definitive, though the results of remediation (eg pump flush) can help to firm up the probable cause.

Summary

Gas hydrates are considered a major flow-assurance challenge in subsea flowlines. They agglomerate rapidly and form hydrate blockages. During transient operations [shut-in and restart (RS)], risk of blockage formation owing to hydrates can be greater compared to that during the continuous operations. In particular, hydrate formation during an unplanned shut-in and subsequent restart could lead to increased operational hazards. In this work, flow-loop tests were conducted under both continuous-pumping (CP) and RS conditions, using Conroe crude oil with three different water fractions (30, 50, 90 vol%) at 5 wt% salinity, over a range of mixture velocities (from 2.4 to 9.4 ft/sec). It was determined that RS operations resulted in an earlier onset of hydrate particle bedding—twice as fast as those in CP tests—from the interpretation of pressure-drop and mass-flow-rate (MFR) measurements. Droplet imaging using a particle vision and measurement (PVM) probe suggested larger water droplets (100–300 µm) during the shut-in, as compared to the CP tests (=40 µm) at 50 and 90 vol% water cuts (WCs). For the tests performed using a demulsifier at 200 ppm, PVM images suggested larger water droplets (mean droplet size = 94 µm), as compared with the test with no demulsifier (mean droplet size = 21 µm). The test using a demulsifier resulted in higher pressure drops and lower MFRs compared with the test with no demulsifier, indicating poor hydrate transportability when water was partially dispersed in the oil phase. The current study indicated that partially dispersed systems present greater risks of hydrate plugging as compared with the fully dispersed systems in the range of water volume fractions from 50 to 95 vol% WC, which was the phase inversion point of the water-in-crude-oil (Conroe14 crude) system. The flow-loop-test analyses presented in this work can potentially aid in an improved mechanistic understanding of RS operations, involving unplanned shut-ins and restarts.

Autonomous inflow control devices (AICDs) have recently been introduced in the petroleum industry to restrict the production of unwanted fluids, namely water and gas, much more effectively than conventional inflow control devices (ICDs). As with ICDs, AICDs are installed downhole along the completion string to first delay water/gas coning and then restrict their influx, without well intervention, if/when coning such occurs. Unlike ICDs, AICDs selectively choke back water and gas significantly more so than oil.

A novel cyclonic AICD was recently developed using computational fluid dynamics (CFD) driven design optimization. The cyclonic AICD's unique internal geometry increases the flow resistance to unwanted fluids based on how their viscosities and densities differ from oil, as initially predicted using CFD and subsequently validated by extensive, carefully controlled single- and two-phase flow tests. The resulting excellent match obtained between CFD and such laboratory tests yielded accurate mathematical models for predicting flow performance over a broad range of flow rates and oil, water and gas properties.

The flow performance models were then incorporated into a state-of-the-art dynamic reservoir simulator with multi-segmented wellbore capability to compare the production performance over time for the same well but completed with no ICDs, conventional ICDs, and cyclonic AICDs. A synthetic but realistic three- dimensional (3-D) reservoir model has used that allowed oil, gas and water production. Multiple sensitivity runs were initially performed to optimize the number of compartments using packers for annular isolation, and the number of ICDs per compartment. Once these parameters were optimized, only the ICD type was varied for performance comparison.

The results of this systematic, multi-step process, as presented herein, demonstrate that the cyclonic AICD adds significant value to the improvement of oil production by controlling unwanted fluids, such as water and gas, and by preserving the reservoir energy.

Integrated simulation of reservoirs, wells, and surface facilities is becoming increasingly popular for modeling hydrocarbon production from deep offshore assets. Currently, there exist two common approaches for the integration. The first approach employs separate reservoir and facility simulators; whereas, the second approach combines the two within one reservoir simulation framework. Both approaches have advantages and drawbacks. For example, the first approach can be more accurate for the facility modeling, but overall it suffers from stability issues and long running times. On the other hand, the second approach is always numerically stable and typically provides better runtime performance, but requires additional inputs, e.g., Vertical Lift Performance (VLP) tables. Preparation of these additional inputs can be time consuming and often error-prone. Moreover, the VLP tables used in the second approach are typically constructed with the averaged values of "auxiliary" parameters, such as inlet temperature, water salinity, etc. This averaging can potentially lead to inaccuracies during simulation.

In this paper, we propose a new framework for integrated asset modeling which combines the benefits of the two approaches and hence significantly improves the efficiencies in both workflow construction and simulation accuracy. Our framework is based on the previously presented fully coupled network approach implemented as an in-house extension to a reservoir simulator. Here we extend the approach by introduction of an additional coupling step with a separate pipe flow (network) simulator. However, instead of using the pipe flow simulator to solve the network, it is used only to dynamically generate the VLP tables for the simulator's internal network module. Comparing to the previous fully coupled network approach, our new approach streamlines the simulation workflow by avoiding the necessity of the additional manually created network input. Furthermore this new approach also improves the modeling accuracy by using a generalization of the VLP description (e.g. with temperature as additional dimension) and by avoiding tables extrapolations. In this paper we discuss the new workflow and the new dynamic generalized VLP table construction in details.

Inflow Control Devices (ICDs) are being increasingly used in complex, heterogeneous reservoirs to make the inflow profile more uniform, delay breakthrough of water and/or gas and limit differential depletion, which can lead to crossflow and other detrimental phenomena. However, ICDs not only alter inflow behaviour: they also affect outflow of fluid during chemical treatments, such as scale squeezes, stimulation, etc., which may be applied periodically during well life.

Methods to account for the additional flow resistance from ICDs when predicting placement of bullheaded treatments are discussed in this paper, in particular, to evaluate whether a theoretical approach based upon Bernoulli's Theorem leads to sufficiently accurate predictions in the absence of laboratory correlations between pressure drop across the ICD and flow rate. This approach may also become significant where the laboratory calibration might be expected to have changed during well life, such as, under the influence of erosion.

The paper describes two analytical methods of simulating placement in a multi-zone well in a heterogeneous reservoir in the Middle East: the first is empirical and models the pressure drop using an equation derived from calibration data in the laboratory; the second uses the Bernoulli equation, and is theoretical. For the empirical approach, the laboratory-based pressure-drop/flowrate calibration data were fitted to an equation, with parameters that depended upon the nozzle dimensions. The theoretical approach calculated the pressure drop using the Bernoulli equation for a cylindrical ICD nozzle. Both methods were used to simulate placement of a generic scale-inhibitor squeeze treatment and the corresponding chemical returns for each zone in the well. In general, the differences in the predictions between the two models were found to be very minor, showing that a theoretical approach is sufficiently accurate to design and evaluate chemical treatments in wells fitted with ICDs in most cases.

This means a very rapid analytical approach can be used to design and evaluate near-wellbore treatments in such wells without resorting to much more complex, numerical-based reservoir simulators, even when calibration data about the ICD performance are not available.

Recent times have seen an advancement in the area of carbonate acidizing, moving forward from single-phase to two-phase analyses, in an effort to account for the presence of the oil-phase during stimulation treatments. Yet, a lack of a complete capability to understand this complex subsurface process still exists. Characterizing the effect of CO₂ (carbon dioxide), a byproduct of the chemical reaction between carbonates & HCl (hydrochloric acid) has been ignored till date, under the pretext of using high pore pressures to keep CO₂ dissolved in surrounding solution. The presence of CO₂ in porous media changes the dynamics of fluid flow.

A three-phase two-scale simulation model is described toward the purpose of accurately modeling the physics of carbonate acidizing. A validation of the model, is conducted using published literature experiments and conducted laboratory corefloods in the area of carbonate acidizing. The acid efficiency curve for a single phase scenario from literature is matched, with the effects of the evolved CO₂ being modeled. Two Indiana limestone core, 6 in. by length and 1.5 in. by diameter, are used for the purpose of a tracer injection study using 5 wt% KCl (potassium chloride) solution, and acid injection study using 15 wt% HCl solution. The experiments were conducted at 71.6°F, and 1,180 psi pore pressures. The Indiana limestone cores are characterized via CT (computed tomography) scans, and a detailed, accurate porosity profile of the core is used as input to the simulation model. The tracer fluid was used to characterize the porous environment and effective dispersion coefficients, and for subsequent calibration of the simulation model. From the conducted single phase acidizing coreflood, the experimental parameters such as pressure drop curves are closely monitored to assess acid breakthrough, and the effluents from the acid coreflood are analyzed for determining the concentrations of CaCl₂ (calcium chloride) and HCl with time. CT scans of the core post acidizing describes the wormhole pattern. These parameters are accurately matched using the simulation model, and subsequent sensitivity studies with the presence of oil are performed thereof.

The modeling of CO₂ as a separate phase for mimicking the acid coreflood played a major role in acquiring a better match with all experimental parameters, with limited dependency on empirical pore-scale parameters. It is shown that the rock-wettability for an oil-water system has a large degree of influence on the acid PVbt (pore volumes of acid required to breakthrough), with oil-wet systems requiring higher volumes. An approximate of 30% recovery of the residual oil in place is predicted, purely based on capability of the evolved CO₂ to swell the surrounding oil.

Matrix acidizing is used for permeability and productivity enhancement purposes in oil and gas wells. Hydrochloric acid has been always a first choice due to so many advantages that it can offer. However, HCl in high pressure/high-temperature (HP/HT) wells is a concern because of its high reactivity resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. There are several alternatives to HCl, among them emulsified acid is a favorable choice due to inherent corrosion inhibition, deeper penetration into the reservoir, less asphaltene/sludge problems, and better acid distribution due to its higher viscosity. Furthermore, the success of the latter system is dependent upon the stability of the emulsion especially at high temperatures. The emulsified acid must be stable until it is properly placed and it also should be compatible with other additives in an acidizing package. This study presents the development of a stable emulsified acid at 300°F through investigating some novel aliphatic non-ionic surfactants.

This paper introduces new non-aromatic non-ionic surfactant to form an emulsified acid for HP/HT wells where the conventional acidizing systems face some shortcomings. The type and quality of the emulsified acid was assessed through conductivity measurements and drop test. Thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. Lumisizer and Turbiscan were used to determine the stability and average particle size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 200°F as a function of shear rates (0.1-1000 s^-1). The microscopy study was used to examine the shape and distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes. Inductively Coupled Plasma (ICP) and Computed Tomography (CT) scan were used to determine dissolved cations and wormhole propagation, respectively.

Superior stimulation results with low pore volume of acid to breakthrough were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branch wormholes resulted from some of the treatments using conventional emulsified acid systems. The results showed that a non-ionic surfactant with a right chemistry such as suitable hydrophobe chain length and structure can form a stable emulsified acid.

This study will assist in creating a stable emulsified acid system through introducing the new and effective aliphatic non-ionic surfactants, which lead to deeper penetration of acid with low pore volume to breakthrough. This new emulsified acid system efficiently stimulates HP/HT carbonate reservoirs.

A new class of permanent clay stabilizers has been developed inorganic based on an aluminum/zirconium-based compound. The increased charge density of the molecule allows it to bind more strongly to swelling clays, while its relatively low molecular weight allows it to stabilize the clay permanently without causing formation damage by blocking the pore throats and reducing permeability.

The most commonly used clay stabilizers are organic and inorganic chloride salts including trimethylammonium chloride, potassium chloride, and choline chloride. These salts have been used for years, are effective in most wells, and are both cheap and abundant. However, their high water solubility and the relatively small size of the cation means that these products are highly mobile and thus are quickly washed away during flowback. Several chemical derivatives were made from a tri-functional amine by reacting it with organic and inorganic acids such HCl, acetic acid, and formic acid; as well as alkylating agents, including chloromethane, benzyl chloride, diethyl sulfate, and paraformaldehyde.

Certain cationic polymers have also proven useful as clay stabilizers. These much larger molecules are not as easily washed away due to steric hindrance and a much higher charge density per molecule. These products have proved useful as long-term clay stabilizers, but their high molecular weights can lead to formation damage by causing them to be filtered out on the rock face.

In this research, several laboratory tests were carried out on the new clay stabilizer. These tests included coreflood experiments conducted on Berea sandstone cores to assess the stabilizer at high temperatures and the influence of different acids on its performance. Coreflood effluent samples were analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES) to measure the concentrations of aluminum and zirconium.

This new permanent clay stabilizer improved productivity from formations that have high clay content by minimizing clay swelling and thus preventing formation damage caused by clogged pore throats and subsequent loss of permeability. It worked well at temperatures up to 250°F and with 15 wt% HCl and regular mud acid (12 wt% HCl, 3 wt% HF).