Hydrate prevention with gas expansion, subsurface heat

Results achieved on the Santo Stefano Mare Field off Italy

J.L. Beauquin
J.C. Fechant
Elf Aquitaine Production

C. Falappa
Elf Idrocarburi Italiana

Hydrate formation curve for the Santo Stefano Mere gas [35,888 bytes]

The development and production of gas field often suffer from the problem of gas hydrate formation in transport lines. If hydrate deposits, which result from a too-low temperature of the gas for a given outlet pressure, are neither prevented from forming nor eliminated, they tend to obstruct the pipeline, resulting in loss of production. Now, the pressure drop across a wellhead choke valve causes the temperature of the effluent to decrease.

One of the possible ways of avoiding this undesirable phenomenon consists in reducing the temperature losses of the effluent. In order to achieve this, Elf Aquitaine Production has set out to use heat available underground in the vicinity of the well. Two distinct but complementary techniques were used in February 1996 on the Santo Stefano Mare offshore gas field operated by the Elf Idrocarburi Italiana/S.P.I. consortium.

One of the techniques consists in reducing the effluent heat loss by insulating the tubing with a gas-oil gel. For the other approach, heat is extracted from the soil layers traversed by the well by the way of an early expansion of the gas downhole.

At the entrance of the evacuation pipe, a temperature gain of more than 40 degrees C, for wells flowing at 65,000 cu meters/day (65 kSm3/d) has been obtained with a simple downhole choke installed by wireline at the lower end of the tubing. As a result, the need for injection of inhibitor (diethylene glycol or DEG) was avoided, resulting in significant saving. The saving resulting from the thermal insulation of the tubing was less marked. However, the results show that an optimized combination of the two techniques would result in much higher heat gains.

This document presents encouraging results recorded on four producing wells from January to October 1996. The paper compares and analyzes the thermal profiles of producing wells based on these trials. The spin-offs of these experiments are of great importance for gas field economics, where hydrate problems are almost always encountered, particularly offshore, in deep water or in cold regions.

Santo Stefano Mare case

Santo Stefano Mare is a gas-producing field located a few km off the coast of Italy in the Adriatic Sea. The gas is essentially made up of methane. The reservoir depth is on average 1,500 meters, while the water depth is 12 meters. The produced gas is evacuated via a 6-in. pipeline to the treatment and compression center located onshore from where it is then sent to the local gas distribution network.

The pipeline starts from the small platform SSM1. It lies on the sea bottom over a distance of 3,350 meters, and is buried over the last 250 meters. An estimate of the water temperature is 20 degrees C in the summer and 5 degrees C in the winter.

For San Stefano Mare, the occasional risk of hydrate formation was limited to wells with high wellhead pressures. DEG was injected in these wells, usually during the winter season when temperatures were in the hydrate formation range. Added to the cost of the operation of DEG injection (products and logistic included), another detrimental impact was that the water treatment process located onshore was affected.

The experimental campaign set out hereafter was defined within the framework of an extension project of the field. Hydrate problems were anticipated as new high pressure reservoirs were targeted for production. The objective of the campaign was to implement new techniques as well as assess their benefits and operational feasibility. The idea was to take advantage of heavy intervention work scheduled for the wells.

As a result, two alternatives to prevent hydrate formation were tested: thermal insulation of the well and a downhole expansion of the gas. In the event of a success, the use of inhibitors, with its negative impact, would be avoided.

The prevalent method used was to attack the root of the problem in order to minimize the remedial costs. By closely investigating the thermodynamic path of the fluid from the reservoir to the production center, and by analyzing the hydrate formation mechanism, attractive solutions, based solely on the available natural resources soon appeared. These solutions drew on the untapped energy accumulated underground in the vicinity of the well.

Origin of hydrates

At San Stefano Mare, initial reservoir pressure is high and production rate has to be kept low to avoid water coning. The result is that bottom hole flowing pressure is high. Control of the flow rate requires an artificial pressure drop somewhere. If this artificial pressure drop is imposed at the wellhead, hydrates will form.

A low flow rate is also the explanation for a relatively low temperature at the wellhead before the choke. The velocity of the moving fluid is low enough for almost all the heat to be dissipated outside of the tubing. A large pressure drop on an already cold fluid will necessarily increase the risk of hydrate formations.

To remedy this situation, the first reaction was to insulate the production tubing, site of most of the calorific losses. However, an initial investigation demonstrated that this approach would not be sufficient. In order to control the well, severely choking the flow is a necessity. However, preserving the natural heat found in the fluid at the reservoir level would not be sufficient to avoid hydrates downstream of the wellhead.

Downhole gas expansion

A controlled, progressive, pressure decrease, favorable to reaching a temperature equilibrium with the surrounding medium, was initially considered. In addition, better initial thermodynamic conditions were sought to carry out this pressure decrease. The risk of hydrate formation is less at the bottom of the well as temperature conditions are more favorable. The technology to control, from the surface, a progressive pressure decrease down the hole was not available. Therefore, a two step pressure drop approach was chosen:

An initial, roughly adjusted, gas expansion at the bottom of the well where the pressure and flow rate are high.
A final controlled, gas expansion at the well head, allowing production control.

From the operational perspective, choking the fluid at the bottom of the well using a calibrated orifice plate installed and retrieved by wire-line was the simplest approach.

Packer gel was placed in well SSM7 during re-completion work in January 1996. Packer gel is a gasoil-base thixotropic gel. Its 250 centipoise (cp) at 20 degrees C is a good compromise, enabling pumping for installation while avoiding gel displacement through natural convection once in place.

Pumping 60 cu meters of gel into the annular space between the tubing and the casing lasted 2 1/2 hours. The gel was pumped by reverse circulation through a gateway between the tubing and the annulus (SSD). This operation was carried out without difficulty following

a strict procedure, covering safety and environmental aspects, in force in the Adriatic sea for this type of intervention (closed storage tanks, no pollution allowed, etc.). As it was carried out at the same time as a scheduled work over, the additional cost attributed to the insulation of the well was a marginal US$25,000 for 60 cu meters of gel.

The gel composition is similar to that of gels used for hydraulic fracturing of reservoir formations. The injection of thixotropic gels in annular spaces is used to insulate wells in polar regions when wax or hydrates are a concern. Retrieving the packer gel is occasionally necessary.

Downhole choke

The chokes installed on the four wells (two with double completion) for these trials were in place from January through October of 1996. Installation and retrieval of the chokes was carried out by strong wireline tools. Nonetheless, servicing the San Stefano Mare Field (very small offshore platforms, logistics, etc.) results in high expenditures for wireline operations, despite the limited means required. A full operation with the associated logistical support will cost a minimum of US$20,000.

Several wireline operations were carried out, some of which had nothing to do with installing downhole chokes. However, the rapid drop in bottom pressure on some strings required a quick adjustment of the choke diameter. This diameter was chosen to prevent hydrates from forming at the inlet of the flowline, while retaining the flexibility in the field production and in the adjustment of individual well flow rate in the case of perturbations in the network.

In October 1996, none of the four trial wells exhibited sufficient downhole pressure to warrant the usage of a downhole choke. Anchored on X-type landing nipples with 1.87 in. ID (2 3/8 in. tubing), the chokes were chosen in order to avoid mishaps in operations:

Anchoring systems with anchoring heads exposed to the fluid flow were eliminated.
The chokes were made of ceramics material exhibiting high resistance to abrasion. In fact, no wear and tear was found on the chokes retrieved from the wells.
Extra thickness of the tubing (flow coupling) was included over a height of several meters above the choke in order to alleviate any piercing through the wall due to turbulences generated by the restriction. A caliper measurement on well SSM1-TL in April 1996 did not reveal any erosion damage at that location.

Ideally, the best solution would be to isolate the tubing between 600 meters and the surface. However, the function of the downhole choke and the elevation where heat exchanges are inverted will fluctuate during the life of the well. It is therefore difficult to account for this variability in the design of the annular space. It is worth remembering that the insulation solution offers several advantages over the downhole choke solution in various configurations:

When depletion is such that the use of a downhole choke cannot be justified and would hinder production (this was the case in trial wells).
When re-opened, an insulated well will evacuate a warm fluid which will transfer heat to the flowline and to the evacuation pipe (this was the case following a shutdown).

Economical gain

The techniques implemented during these trials have been successful in preventing gases from entering in the thermodynamically stable area of hydrate formation. As a result, the injection of hydrates inhibitors was suspended. For a well with 65,000 cu meters/day, this represents a saving of 76 liters/day of DEG, or roughly a saving of US$42,000/year/well. Globally, however, the saving is reduced as the four wells considered were rapidly depleted, the initial high pressure being at the root of the problem.

Expenditures associated with implementing these solutions have to be borne in mind: US$25,000 for gasoil gel for an annular volume of 60 cu meters if the operation is carried out at the same time as a scheduled work over. Wireline operations amount to US$20,000 per intervention. This is exceptionally high, due to the particularity of this field. These operations have to be limited and programmed as part of overall campaigns.

We have not identified any severe limitation to implementing these techniques. Nonetheless, the following has to be kept in mind:

A limitation to installing a downhole choke comes from the availability of a landing nipple in the tubing at the adequate depth. This landing nipple must be installed during completion. For tubings with diameters above 3 1/2 in., a nippleless mandrel can be used as no landing nipple is necessary.
Although we were not made aware of any incident, possible sand encroachment will most likely limit the use of a downhole choke. This is especially true if the completion is not designed with an over thickness of metal above the landing nipple as this situation may lead to piercing of the wall. Similarly, the initial clearing of the well may cause sediments to circulate. The operator must be extremely vigilant if a downhole choke is installed.
Wireline operations are never without risk. This risk must be weighed in the light of the completion data in a given context, namely the depth, the diameter, the number of restrictions and deviation of the well.

Conclusions

These trials have demonstrated the technical and economical feasibility of alternative solutions to handle hydrate problems. The techniques used are relatively simple and offer a fair amount of flexibility. Both methods described are applicable in a number of areas where gas wells are operated.

On top of their economical aspects, these techniques have the major advantage of being environment-friendly. They reduce or eliminate chemical pollution. They tap into an available natural energy resource - one may even say a limitless resource - which is ours to use in our trade: the heat stored in the rock.

One may also note that these techniques are an example of process being gradually taken further upstream namely inside the well. The successful implementation on site of the proposed methods is at any rate the outcome of a multi-disciplinary collaboration involving drilling, completion, and process engineers.

Acknowledgements:

This is an edited version of a technical paper presented at the Offshore Mediterranean Conference and Exhibition (OMC '97) in Ravenna, Italy in March. The authors acknowledge Elf Aquitaine Production, Elf Idrocarburi Italiana and Societa Petrolifera Italiana S.p.a. SPI for allowing publication of this paper, and thank A. Carestia, R. Cavicchia, M. Geniteau, J. Poublan, and V. Saubestre for their help in the preparation.