U.S. patent number 3,815,673 [Application Number 05/226,843] was granted by the patent office on 1974-06-11 for method and apparatus for controlling hydrostatic pressure gradient in offshore drilling operations.
This patent grant is currently assigned to Esso Production Research Company. Invention is credited to George H. Bruce, William T. Ilfrey.
United States Patent |
3,815,673 |
Bruce , et al. |
June 11, 1974 |
METHOD AND APPARATUS FOR CONTROLLING HYDROSTATIC PRESSURE GRADIENT
IN OFFSHORE DRILLING OPERATIONS
Abstract
An improved system for offshore drilling is disclosed which is
particularly useful in those operations where a floating vessel is
situated at the surface of a body of water and circulation of
drilling fluid is accomplished by introducing drilling fluid into a
drill string extending from the vessel into a borehole in the floor
of the body of water and returning it through a separate conduit to
the vessel. A surface detectable signal is generated which is
proportional to the hydrostatic head exerted by the drilling fluid
within the return conduit. Hydrostatic head of the drilling fluid
within the return conduit is controlled in response to the signal,
as by injecting gas into the conduit near its lower end, to
regulate the hydrostatic head of the fluid in the borehole.
Inventors: |
Bruce; George H. (Houston,
TX), Ilfrey; William T. (Houston, TX) |
Assignee: |
Esso Production Research
Company (Houston, TX)
|
Family
ID: |
22850648 |
Appl.
No.: |
05/226,843 |
Filed: |
February 16, 1972 |
Current U.S.
Class: |
166/359; 175/25;
175/7; 175/72 |
Current CPC
Class: |
E21B
7/128 (20130101); E21B 21/001 (20130101); E21B
21/08 (20130101) |
Current International
Class: |
E21B
21/08 (20060101); E21B 21/00 (20060101); E21B
7/12 (20060101); E21B 7/128 (20060101); E21b
007/12 () |
Field of
Search: |
;175/25,38,5,72,48,7,50,69 ;166/.5,.6 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Sutherland; Henry C.
Assistant Examiner: Favreau; Richard E.
Attorney, Agent or Firm: Gilchrist; James E.
Claims
What is claimed is:
1. In a method of drilling wherein a floating vessel is situated at
the surface of a body of water and drilling fluid is introduced
into a drill string extending from the vessel into a borehole in
the floor of the body of water and returned to the vessel through a
separate conduit which conduit is provided with means for injecting
a gas thereinto near its lower end, the improvement comprising
measuring the hydrostatic pressure of the drilling fluid within
said return conduit beneath the gas injection point and adjusting
the pressure gradient of the fluid contained within the return
conduit to maintain the hydrostatic pressure of the drilling fluid
within the borehole at a level sufficient to counterbalance
formation pressure without exceeding its fracture gradient.
2. The method of claim 1 wherein said gas is an inert gas.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to an improved system for drilling from a
floating vessel which involves monitoring and controlling the
hydrostatic head of the drilling fluid returns to control bottom
hole pressure.
2. Description of the Prior Art
In recent years the search for offshore deposits of crude oil and
natural gas has been extended into ever deeper waters overlying the
continental shelves. With increased water depths the conduct of
drilling operations from floating vessels has become more prevalent
since economic considerations militate against the use of
bottom-founded drilling platforms commonly used in shallow water.
In these operations the drill rig and associated equipment are
positioned aboard a floating vessel which is stationed over the
wellsite. The drill string extends from the vessel to a wellhead
situated on the floor of the body of water and a separate return
conduit, normally a riser pipe, is provided to permit circulation
of drilling fluid.
Control of the influx of fluid from pressurized subsurface
formations is an important aspect of any drilling operation. If
uncontrolled, fluid influx can lead to a blowout and fire,
frequently with catastrophic results in terms of loss of life,
damage to property, and pollution of the seaway. Conventionally,
well control is established by maintaining the density of the
drilling fluid and thus the hydrostatic pressure exerted on the
subsurface formations at a level sufficient to overcome formation
pressures. At the same time, caution is necessary to assure that
the density and hence pressure gradient of the column of fluid does
not exceed the natural fracture gradient of the formation, i.e.,
the pressure gradient necessary to initiate and propagate a
fracture in the formation.
In deep water, the natural fracture gradient of shallow formations
is particularly critical factor. It is directly related to the bulk
density of the sediments resting on top of the pressurized
formation and thus at the floor of the body of water is for all
practical purposes the pressure gradient of water. For a formation
situated 500 feet below the floor of a body of water having a depth
of 2,000 feet, the natural fracture gradient will be greatly
influenced by the gradient of the overlying body of water. Because
of the higher bulk density of rock, however, the fracture gradient
rapidly increases with the depth of penetration into the sea floor
and will not represent a serious problem after the first few
thousand feet of hole are drilled.
During the drilling of the surface hole (the first few thousand
feet) the hydrostatic head of the drilling fluid should not greatly
exceed that of a column of salt water to minimize the possibility
of formation fracture. On the other hand, normally pressured
formations have a pressure similar to that exerted by a column of
salt water corresponding to formation depth. It will therefore be
apparent that in deep water, achieving a hydrostatic head high
enough to control the well and yet low enough to prevent fracturing
subsurface formations will require careful control of the pressure
gradient of the drilling fluid.
In offshore operations controlling the density of the fluid as it
is pumped into the well is not an entirely satisfactory approach
since at normal drilling rates the drill cuttings suspended in the
returning drilling fluid may sufficiently increase its density to
yield a gradient exceeding normal fracture gradient. Heretofore,
the only available system to assure a balanced condition in these
circumstances was to greatly increase drilling fluid circulation
rate or to reduce the rate of penetration; both practices are
economically unattractive. A need therefore exists for a system for
controlling the hydrostatic head of the drilling fluid within close
limits without either increasing drilling fluid circulation rate or
reducing the penetration rate.
SUMMARY OF THE INVENTION
The present invention permits close control over the pressure
gradient of the drilling fluid at no sacrifice of penetration rate
and with no increase in circulation rate and thus alleviates the
difficulties encountered in deep water drilling which are outlined
above. In accordance with the present invention the hydrostatic
pressure exerted by the drilling fluid within the drilling riser or
other return conduit is monitored and its density is regulated to
control the hydrostatic head of the mud column and thereby assure
sufficient hydrostatic pressure to counterbalance formation
pressures without exceeding their fracture gradients.
The system of the present invention is particularly applicable to
drilling operations wherein a floating vessel is situated at the
surface of a body of water above a wellhead positioned on the floor
thereof. Drilling fluid is introduced into a drill string that
extends between the vessel and wellhead and is returned through a
separate conduit. The apparatus of the invention includes a means
mounted on the conduit for generating a signal proportional to the
pressure therein and detectable at said vessel. The method involves
monitoring the hydrostatic head of the fluid flowing within the
conduit and regulating its density to control the hydrostatic head
of the column of drilling fluid acting on subsurface formations.
The pressure gradient of the fluid within the return conduit can be
reduced by injecting gas into the conduit. The rate of gas
injection is controlled in response to the pressure within the
riser to maintain the hydrostatic head at a substantially constant
level, thereby assuring the proper hydrostatic head will be
maintained on formations exposed to the borehole.
It will theerefore be apparent that the present invention will
permit the hydrostatic pressures exerted by drilling fluids and
entrained cuttings to be closely controlled without any substantial
reduction in drilling rate or increase in circulation rate. The
present invention thus permits control of pressurized formations
during normal drilling operations while reducing the danger of
exceeding their fracture gradients and offers significant
advantages over systems existing heretofore.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 depicts typical curves relating fracture gradient to
formation depths beneath the water surface.
FIG. 2 is an elevation view, partially in section, of a floating
drilling vessel provided with apparatus necessary to carry out the
method of the invention.
FIG. 3 is a schematic flow diagram of a system for monitoring and
regulating the hydrostatic head of the drilling fluid within the
return conduit in accordance with the present invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
FIG. 1 is a plot of formation depth in thousands of feet versus the
natural fracture gradient expressed both in psi/ft and as an
equivalent mud density in lbs/gal (ppg). The curves shown are for a
particular geographic area but illustrate the general relationship
between water depth and formation fracture gradient. It will be
apparent from an inspection of FIG. 1 that for any particular depth
from the water surface, the fracture gradient decreases markedly as
water depth increases.
Curve A relates the fracture gradients of formations encountered
onshore to depth. These range from 0.60 psi/ft at 1,000 ft up to
about 0.69 psi/ft at 3,000 ft. Curve B is for similar strata at a
water depth of 750 ft. The fracture gradient is thus that of sea
water, about 0.44 psi/ft, for depths to 750 ft. A formation buried
under 1,000 ft of sediments is 1,750 ft below the water surface and
will be noted to have a fracture gradient on the order of 0.54
psi/ft. The gradient at 3,000 ft beneath the sea floor (3,750 ft
below the water surface) is 0.64 psi/ft. Curve C represents
identical sediments under 1,500 ft of water. The natural fracture
gradient for a formation under 1,000 ft of sediments corresponds to
a depth of 2,500 ft and will be noted to be 0.51 psi/ft,
corresponding to a mud weight just under 10 ppg. At 3,000 ft of
penetration, the fracture gradient is 0.61 psi/ft. It will
therefore be apparent that for any particular depth of penetration
into the substrata, the fracture gradient decreases as water depth
increases.
The importance of the decrease in fracture gradient with water
depth can be demonstrated by an example comparison of the
hydrostatic pressure required to maintain well control to that
which will fracture the formation. A normally pressured subsurface
formation can be anticipated to have a formation pressure
equivalent to the pressure exerted by a column of salt water having
a height equal to formation depth. A gas formation 1,000 ft beneath
the floor of a 1,500 ft body of water could therefore be expected
to have a pressure equal to the product of the salt water gradient
and the depth of the formation beneath the water surface or about
1,110 psi and a drilling fluid having a salt water gradient (0.445
psi/ft, or about 8.5 ppg) could be expected to balance the
formation pressure. It is normally desirable to drill with a fluid
having a degree of overbalance, i.e., exerting a hydrostatic head
greater than formation pressure. On the other hand, the fracture
gradient at this depth is 0.51 psi/ft, which corresponds to a
bottom hole pressure of 1,275 psi. Thus the pressure exerted by the
mud must be kept between 1,110 and 1,275 psi. This in turn dictates
a mud density between 8.5 ppg, corresponding to the salt water
gradient and 9.8 ppg which could be expected to break down the
formation with attendant loss of drilling fluid and well control.
While compounding a drilling fluid which will have a density in
this range is a simple matter, maintaining it at the required level
during the course of the drilling operation is a somewhat more
complex problem.
By and large, shallower formations permit more rapid penetration by
the bit than do deeper formations. Accordingly, the surface hole is
normally drilled at a relatively rapid rate. At the same time,
rapid drilling leads to an increase in the volume of drilled solids
in the mud, substantially increasing its density. Although not a
problem onshore or at shallow water depths, because of the
decreased fracture gradient, this increase in density creates
problems in deep water. The difficulties could of course be
overcome by drilling at reduced rates and simultaneously increasing
the rate of circulation, thereby assuring that the drilling fluid
density remains within the critical range. This approach is however
economically very unattractive in view of the daily expense of
maintaining drilling equipment at the wellsite.
An alternative approach is to drill at a rapid penetration rate and
at the same time reduce the bottom hole pressure of the drilling
fluid by injecting gas or other low density material into the riser
to lighten the mud. At the same time, however, a gas injection
program undertaken in deep water requires careful control to assure
that the hydrostatic head of the drilling fluid remains between
that necessary to control the well and that which would result in a
fracturing of the formation. It is therefore an important aspect of
the present invention to monitor the pressure exerted by the
drilling fluid within the return conduit and to adjust the density
of the fluid therein to control bottom hole pressure. Control of
fluid density is preferably accomplished by injecting gas into the
riser near the lower end at a rate regulated in response to the
pressure therewithin to maintain the total hydrostatic head of the
drilling fluid acting on a subsurface formation within the range
necessary to assure control of the well without fracturing the
formation.
FIG. 2 shows a drilling vessel 11 floating on a body of water 13
and equipped to carry out the method of the present invention. A
wellhead 15 is positioned on the floor 17 of the body of water. A
drill string 19 is suspended from derrick 21 mounted on the vessel
and extends between it and the wellhead. Drilling fluid is pumped
down the string of drill pipe through the bit and into the borehole
and returns to the vessel via a return condit shown as drilling
riser 23. A high pressure gas source 25 is situated aboard the
vessel. Injection conduit 31 extends from the control valve down
the length of the riser to a level near the wellhead. One or
preferably a plurality of gas lift valves 33 are positioned between
the injection line and the drilling riser. The lift valves are
normally preset to open at a given differential pressure. A
pressure sensor 35 is shown positioned near the lower end of the
drilling riser and arranged to sense riser internal pressure. It
may for example be a pressure transducer which generates an
electrical signal proportional to pressure within the return
conduit. The signal is conducted to the surface by means of
electrical conductor 37 extending between the pressure transducer
and the drilling vessel. It may be directed to controller 39 which
controls the position of routing valve 29 in response to the
amplitude of the pressure signal to regulate the rate at which gas
is introduced into the lower portion of the drilling riser. By
properly adjusting the response characteristics of the valve
controller, the pressure gradient of the fluid within the drilling
riser can be closely controlled.
FIG. 3 is an exemplary flow diagram of apparatus which can be used
to implement the method of the invention. An inert gas source is
designated by numeral 41 and is preferably engine exhaust gas or
the product from an inert gas generator. Exhaust gas is routed
through conduit 43 to gas treater 45. Nitrogen oxide and water are
separated from the source gas and the residue, which consists
primarily of nitrogen, carbon dioxide and water, is piped through
conduit 47 to compressor 49. The gas is then compressed through
stages, as required, to sufficiently increase its pressure. For
depths of 1,000-2,000 ft, 1,500 psi will normally suffice. The high
pressure gas is conveyed to cooler 53 which condenses any residual
water and cools the compressed gas to about 100.degree.F. Normally,
the dry, high pressure gas passes from treating unit 53 via line 27
to routing valve 29. In the event of excess pressure, however,
release valve 55 opens and discharges the gas through exhaust line
57, returning the inert gas to the atmosphere. Under normal
pressure conditions, the release valve remains closed and routing
valve 29 diverts part of the gas down injection line 31 to lighten
the drilling fluid and recycles the remainder through conduit 59
leading back to the compressor. The percentage of gas diverted into
the riser is controlled by valve controller 39 in response to a
surface detectable signal proportional to pressure within the riser
which is generated from pressure sensor 35 situated near the base
of the riser and may, for example, be conducted to the vessel by
means of electrical conductor 37 leading to the valve controller.
The signal could alternatively be transmitted acoustically,
pneumatically or by other means as well.
High pressure gas routed into injection conduit 31 travels
downwardly and into the riser through differential-pressure
actuated gas lift valves 33. These valves are preferably vertically
spaced to assist in unloading the riser whenever drilling
operations have been interrupted for a period of time. Gas is
injected into the interior of the conductor pipe in the annulus
surrounding the drill pipe and the lift gas and drilling fluid flow
upwardly to rotating drilling head 61 which diverts the gas-mud
mixture away from the drill floor. Both gas and mud are diverted
through conduit 63 to separator 65 wherein the inert gas is
separated from the mud as by means of gravity segregation. The gas
is exhausted to the atmosphere via exhaust conduit 57 while the mud
is returned through line 67 to the mud pits for recirculation.
* * * * *