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The Water Injection Process
0263–8762/03/$23.50+0.00 # Institution of Chemical Engineers Trans IChemE, Vol 81, Part A, March 2003
www.ingentaselect.com=titles=02638762.htm
THE WATER INJECTION PROCESS A Technical and Economic Integrated Approach B. PALSSON, D. R. DAVIES, A. C. TODD and J. M. SOMERVILLE Heriot–Watt University, Edinburgh, UK
W
ater injection is an essential part of many modern oil eld development plans. Highcost offshore developments require that the water ood process equipment is designed and installed prior to acquiring any injection experience on that particular eld. The chosen design must not only maximize the oil production revenue, but also carry an acceptable level of risk in terms of the project costs and technical uncertainties. This paper describes a holistic approach for an economic evaluation of the water injection process, integrating the key technical and economical elements. Well injectivity, which describes the well-to-reservoir connection, is a central factor in any water injection operation. The formation characteristics, water properties, well con guration and the injection water pressure determine this. Injection well behaviour is dominated by fracture geometry if the well is operated at suf ciently high pressure. By contrast, the injectivity of a well operated under matrix conditions (below fracture pressure) is dominated by formation damage caused by impurities in the injection water. This paper highlights the role of well injectivity provides a quantitative framework and a worked example of how decisions concerning design and operation of the water ood plant, process and wells can be made. Keywords: water injection; well injectivity; formation damage; environmental impact; techno-economics.
recovery and increases the water handling costs. This will have a severe impact on the potential project pro tability, as well as adding to the general uncertainty in eld performance. This paper describes a holistic approach for modern water injection management. It shows how the value of water injection can be estimated and provides an economic framework for the evaluation of the water injection process by integrating the key technical and economic elements.
INTRODUCTION Water injection is a key element in modern oil eld operations. Many offshore oil eld development plans call for water injection into the oil reservoirs for water ooding (sweeping the oil to the producers) and for pressure support ( lling the voidage left by the produced uids); often maintaining the reservoir pressure and well bottomhole owing pressures above the bubble point. Other objectives can also become important in speci c situations, e.g. control of rock compaction etc. A successful water injection scheme can therefore lead to optimum eld development by:
TECHNICAL CHALLENGES WITH WATER INJECTION
(1) maximizing overall recovery—an evenly distributed waterfront sweeps the hydrocarbons towards the producers; (2) accelerating hydrocarbon production by maintaining high reservoir pressure; (3) minimizing water production and the associated water handling cost; and (4) minimizing the projects environmental impact [e.g. halt surface disposal of produced water by its (re)injection into the reservoir].
The main objectives of water injection well operation are to: (1) achieve and sustain the required injection rate with minimum cost (the sum of well, water treatment, pump, workover costs etc.); (2) control the water injection pro le to maximise the sweep ef ciency (e.g. avoid plugging of tight zones and contain water ood induced fractures within the injection zone); and, ultimately, (3) reduce the uncertainty in the expected well injectivity, allowing for more accurate production planning to ensure that project economic objectives are met.
An unsuccessful water injection scheme, resulting in limited reservoir pressure support, poor sweep ef ciency and excessive water production, reduces the overall oil 333
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Many factors contribute to the success of a water ood operation. However, well injectivity can be referred to as the central factor, indicating how much pressure has to be applied to achieve a certain injection rate for given well and formation characteristics, as illustrated in Figure 1. The top triangle in Figure 1 presents the factors affecting well injectivity, such as injection water source, properties and treatment, injection pump capacity and well issues. The lower triangle represents the water ood factors that may be affected by well injectivity, such as the injection pro le, fracture conformance, near-wellbore reservoir cross ow, reservoir pressure support and sweep ef ciency of hydrocarbons. Study of the expected well injectivity is therefore the fundamental technical factor for any water injection system, both at the planning and the operational stages. The latter is especially important as monitoring the performance of injection wells and the treatment plant performance allows modi cations to the injection strategy as a response to changes in well injectivity.
Water Characteristics The properties of the injection water are one of the most important factors in de ning the injectivity. ‘Water Quality’ is determined by the source of the injection water and its treatment prior to injection. Four classes of water injection schemes are encountered in oil eld operations: (1) Surface fresh water injection (SFWI)—the surface water is generally taken from rivers or lakes and is therefore likely to be rich in oxygen and organic matter. SFWI is increasingly uncommon since in most parts of the world surface water is considered too valuable. (2) Sea water injection (SWI)—SWI is the most common option in offshore and coastal environments. The sea water contains traces of both suspended and dissolved minerals, oxygen and bacteria and is therefore often ltered and treated with chemical doses prior to injection to avoid corrosion, bacteria growth and souring.
The properties of the sea water vary greatly depending on the eld location (estuary, river mouth, shallow or deep water, time of year, etc.). Recent developments of raw water injection (RWI) have taken another approach, installing a satellite plant at the seabed for minimum water treatment and injection into wells constructed from corrosion resistant material (Eden et al., 2001). (3) Aquifer water injection (AWI)—aquifer water is a common alternative where sea water is either not available or is incompatible with the injection formation. A special case of AWI is dump ood injection (DFI), where a single well connects the aquifer and injection zones (Davies, 1972). (4) Produced water injection (PWI)—the increasing volume of water co-produced with the oil stream is either injected into a dedicated disposal zone or re-injected into the producing zone. The traces of oil and other chemicals in the produced water make ltration dif cult and the injection operation is therefore more complicated. Recent developments of subsea separation and (re)-injection (SSI) and down-hole oil–water separation (DHOWS) and re-injection are other forms of PWI. The key characteristics of the water injection schemes, such as the concentration of total suspended solids (TSS), total dissolved solids (TDS), oil-in-water (OIW) suspensions and solid particle size (ds), are summarized in Table 1. Table 1 shows the advantages of ‘clear water’ (AW and SW). PWI is, however, rapidly becoming the process of choice to help minimize the eld’s environmental impact. The PW will still contain traces of oil, as well as numerous dissolved or suspended minerals and other organic species. Residues from the various production chemicals injected in the production wells or added in the surface facilities will also be present. The chemical and physical properties of PW and SW for the Prudhoe Bay eld in Alaska and the Ula eld in the Norwegian North Sea are listed in Table 2. Note the varied ion makeup of the different water sources, making generalizations between elds dif cult.
Figure 1. The pivotal role of well injectivity in the water cycle ef ciency. PW, produced water; SW, sea water; AW, aquifer water.
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Environmental issues, organic material Corrosion products, low temperature can cause TIFa Often compatible with connate water Sanding (affects injection), limits in monitoring Minimum SW treatment, corrosion, organic material Large solids, organic material, production chemicals Less chance of PW being exposed to atmosphere Less pressure variation than PWRI, dif cult without access
The main objective of injection well design is to optimize the connection to the injection zone formation. The key technical challenges are to:
Varies Small Small (varies) Small (varies) Medium Large? High? Medium?
None None None None None Medium Medium High
Varies High Medium Medium High High High High
(1) achieve and sustain the required injection rate; (2) control the water injection pro le to maximize the sweep ef ciency; and (3) reduce the uncertainty in the expected injection well operation.
Varies Medium (varies) Low (varies) Low (varies) High High High? High? Thermally induced fractures (TIF).
a
Onshore Offshore Onshore=offshore Onshore (offshore?) Offshore Onshore=offshore Offshore Onshore (offshore?) SFWI SWI AWI DFI RWI PWI SSI DHOWS
335 Well Characteristics
Proven—successful Proven—successful Proven—successful Proven—successful? In development Mixed results In development In development
TDS OIW ds TSS Application Process
Status of technology
Water quality
Table 1. Summary of the key issues for the main water injection schemes.
Comments
THE WATER INJECTION PROCESS
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The well characteristics that have an impact on well injectivity include well deviation and orientation, completion ef ciency and the near-wellbore effects, e.g. drilling and completion damage. Water injection completions are generally designed with the objectives of withstanding high injection pressure and minimizing maintenance costs, e.g. tubing replacements. As for production wells, open-hole completion will provide the best wellbore connection, but selective perforating procedures are often applied where zonal isolation is required. The development of zones with different pressure regimes, connected by the same (injection) wellbore, leads to allocation problems when monitoring the water ood progress. This problem becomes more severe when the well is shut in due to the larger water volumes involved. From a well operation point of view, injection wells in unconsolidated formations, which may be stable during injection, become prone to sand production during cross ow when the well is shut in, resulting in loss of the well due to sanding in the wellbore. Suitable sand control measures need to be in place (Santarelli et al., 1998; Morita et al., 1998; McKay et al., 1998). Most types of sand control completions limit the in ow area and are prone to erosion and particle plugging. Hydraulic fractures have been applied in certain situations to improve the well-to-reservoir connection, especially in tight formations. Propped fractures appear to plug more quickly and result in poorer injectivity performance than non-propped fractures (Palisch et al., 1996). Injection above fracture pressure, resulting in a continuously propagating water ood-induced fracture, has obvious bene ts (Figure 2). A fractured injector has a fundamentally different leak-off mechanism from a non-fractured (matrix) injector, since the fracture has a large formation surface area exposed to the injection water. The fracture also has a large storage capacity for the suspended particles that may be ltered out and will also continuously open up further undamaged (‘clean’) formation at the fracture tip, if the fracture can propagate. To illustrate these differences, a ‘typical’ North Sea injection well, with a 7 inch open hole completion in a 100 m thick interval, has a surface area of 56 m2, whereas a water ood-induced fracture with a half-length of 30 m has effective wellbore of 12,056 m2 or 215 times larger. Injection of 4000 m3 day¡1 (25,000 bpd) of the produced water from the Ula eld (Table 3, TSS ˆ 22 mg l¡1) will carry approximately 90 kg day¡1 of solids; or about 16 m3 year¡1, into the well. If the solids are assumed not to invade the formation and have a solids= lter-cake density of 2000 kg m¡3, there is suf cient volume to ll the matrix wellbore to above the perforations six times during a one year injection period. In contrast, an evenly distributed ltercake on the fracture walls would have a thickness of only
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Table 2. Chemical and physical properties of injection water in two oil elds. Field Prudhoe Bay (Fambrough et al., 1995) Water source Component concentration (mg l¡1) Total suspended solids (TSS) Total lterable solids Mean particle diameter Total oil-in-water (OIW) Temperature (T) pH Density Total dissolved solids Cations sodium (Na‡ ) potassium (K‡ ) magnesium (Mg2‡ ) calcium (Ca2‡ ) strontium (Sr2‡ ) barium (Ba2‡ ) iron (Fe2‡ or Fe3‡ ) Anions chloride (Cl¡) sulphate (SO42) bicarbonate (HCO3¡) Gases free carbon dioxide (CO2) oxygen Bacteria sulphate-reducing bacteria general aerobic bacteria Dissolved hydrocarbons
Ula (Bakke et al., 1995; Hjelmas et al., 1996; van der Zwaag and Øyno, 1996)
PW
SW
IW (65%SW, 35%PW)
PW
N=A 10–15 mg l¡1 N=A 400–600 mg l¡1 N=A 6.8 1019kg m¡3 N=A
4 mg l¡1 N=A 3 mm 0 mg l¡1 18¯ C 8.1 1023 kg m¡3 N=A
6 mg l¡1 22 mg l¡1 N=A 15 mg l¡1 31¯ C 7.3 1035 kg m¡3 N=A
22 mg l¡1 48 mg l¡1 N=A 39 mg l¡1 39¯ C 6.8 N=A 247,107a
8780 mg l¡1 135 mg l¡1 353 mg l¡1 287 mg l¡1 20 mg l¡1 1 mg l¡1 N=A
N=A N=A N=A 410 mg l¡1 8 mg l¡1 0 mg l¡1 0 mg l¡1
N=A N=A N=A 2330 mg l¡1 96 mg l¡1 5 mg l¡1 11 mg l¡1
52,225a 3507a 2249a 6255 mg l¡1 267 mg l¡1 23 mg l¡1 30 mg l¡1
13,200mg l¡1 785 mg l¡1 2350 mg l¡1
19,850mg l¡1 2790 mg l¡1 140 mg l¡1
28,300mg l¡1 1900 mg l¡1 192 mg l¡1
43,700mg l¡1 463 mg l¡1 208 mg l¡1
N=A N=A
7 mg l¡1 80 mg l¡1
52 mg l¡1 15 mg l¡1
175 mg l¡1 0 mg l¡1
N=A N=A N=A
0 count ml¡1 45 count ml¡1 1 mg l¡1
5 count ml¡1 200 count ml¡1 8 mg l¡1
N=A N=A 19 mg l¡1
a
Formation water properties (Warren and Smalley, 1994).
1.4 mm. If the solids did invade the formation, the volume of solids injected each year is suf cient to ll all pores 42 cm into the formation for a matrix well but only 7 mm into the formation surrounding a water ood induced fracture (assuming 20% porosity). Laboratory experiments show that matrix injection (Figure 2a) is dominated by particle plugging (Todd et al., 1984). All matrix injectivity prediction models will therefore predict a large, but smooth, injectivity decline; even for injection of relatively clean sea water into a permeable sandstone (Figure 3a; Sharma et al., 2000). Injection under the condition of thermally=water ood-induced fracturing (Figure 2b) is, however, quite different. Injectivity is generally better sustained and changing from injection of cold SW to warm PW leads to an abrupt reduction in injectivity to a lower level where it remains reasonably constant (Figure 3b; van den Hoek and McLennan, 2000). Injection of water considerably colder than the receiving formation will cool the near-wellbore rock and cause localized stress reduction. This ‘thermally induced fracturing’ (TIF) causes a hydraulic fracture to form at a lower injection pressure than would normally be expected (Perkins and Gonzalez, 1985). A fracture will only be created in the ooded zone, and will be contained within it, if cold water is injected below the in-situ=far- eld stress but above the thermally lowered stress. This reduces the risk of out-ofzone fracturing (Morita et al., 1998). This has been used as a fracture containment procedure when injecting into a new well for the rst time (Stevens et al., 2000).
There are many publications discussing various aspects of thermally induced fractures—it has even been claimed that most water injectors are thermally fractured (Paige and Sweeney, 1993). A multi-well study of the Prudhoe Bay eld performance showed that long-term injection of SW at bottom-hole injection pressure above the thermally lowered formation stress resulted in stable injectivity (Paige et al., 1995). When converted to (warmer) PW, with its higher solids and dispersed oil loading, the injectivity declined rapidly to a lower ‘plateau’ level where it continued to decline slowly (Figure 3b). If the temperature and particle loading are high, the plateau level will be lower and the injectivity decline will be faster. When converted back to
Figure 2. Illustration of the fundamental differences between a non-fractured=matrix (left) and fractured (right) injectors: leak-off area, leak-off mechanism ( ow velocity and direction) and the storage capacity.
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Figure 3. (a) Injectivity decline due to injection of ltered SW under matrix conditions in a Gulf of Mexico eld (permeability 1–4 darcy; Sharma et al., 2000). (b) Injectivity of un ltered SW and PW in an injector with water ood-induced fracture; the Forties eld, well A5-3 (Paige et al., 1995).
cold sea water, the initial injectivity was quickly restored. It has been observed that the well deviation and orientation have a signi cant impact on the fracture propagation pressure when there is a signi cant contrast between the minimum and maximum horizontal stresses (Paige et al., 1995). Modelling of fractured well water injection continues to be a major technical challenge. Many models are capable of matching the observed injectivity but do not describe adequately what happens to the injected solids (van den Hoek and McLennan, 2000). Injection of the Prudhoe Bay PW (Table 2) with a TSS of 15 mg l¡1 at an average rate of 1200 m3 day¡1 (7500 bpd) for 10 years delivers 32.6 m3 of solids into the wellbore. If we assume that the fracture height equals the pay thickness (10 m) and that average fracture width is 5 mm, then the fracture half-length has to be at least 325 m (approximately 1000 ft) if all the solids are stored in a single, narrow fracture. This is a signi cantly longer fracture than standard fracture monitoring methods, such as pressure fall-off tests or hydraulic impedance tests would indicate (van den Hoek and McLennan, 2000). This is a small volume of solids compared with that injected into wells during cuttings re-injection operations (Moschovidis et al., 1998). Rock mechanical models have recently been proposed to account for these large volumes (van den Hoek and McLennan, 2000; Moschovidis et al., 2000). Operational Aspects Once the injection system is installed, alterations to the injection pump power (pressure and ow rate) and the water treatment ef ciency are the most easily adjustable parts of the operation. If injectivity decline occurs, the injection pump pressure can be increased to maintain the required injection rate. However, the injection pressure may be limited by the pump power, well and completion design or by formation issues, e.g. to avoid or limit fracture growth. Impurities in the injection water, such as dissolved minerals, gases and (organic) chemicals as well as suspended particles, are the biggest contributors to injectivity damage. Most sources of water require some form of treatment prior to injection, e.g. chemical dosing, ltration, separation etc. Such water treatment is costly and complete puri cation is impractical. Therefore, a compromise has to be made between the chance of formation damage occurring and the overall impact of the potential damage and the Trans IChemE, Vol 81, Part A, March 2003
remedial options against the cost of more extensive water treatment. A roadmap (Figure 4) has been developed which describes the water quality vs injection damage interrelationship. This lists the main sources of injection damage, the key damage mechanisms as well as how they can be controlled and remedied once damage has occurred. Application will, of course, require making it case-speci c. Figure 4 shows that most of the chemical damage processes are relatively easily controlled if the surface water treatment process plant has been speci ed correctly. By contrast, removal of formation injectivity damage can be more problematic. Further, it is technically impractical to fully remove all solids and dispersed oil from the PW. An economic compromise has to be made between PW treatment options and costs, guided by models or other prediction methods of injection well performance.
Monitori ng Monitoring of the injection system and the downhole injectivity performance is essential to recognize controlling mechanisms and to allow quick response if injectivity damage occurs. Analysis of injection performance also provides valuable information to improve future injection system designs. Water injectivity monitoring is commonly limited to the measurement of the wellhead pressure and injection rate at regular, often widely separated, time intervals. Various graphical methods are used to present the well injectivity performance, e.g. (1) pressure-rate plots; (2) plots of pressure and rate against time; (3) injectivity index or reciprocal injectivity index against time; (4) cumulative injection volume against time; or (5) Hall plot etc. Such plots can identify changes in well injectivity, e.g. (1) an injectivity decline can be due to geological reasons (faults, channelling etc.), a fracture closing or formation damage build-up; (2) an injectivity increase can be caused by a fracture opening, fracture extension or fracturing out-of-zone.
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Figure 4. Source of water injection damage, damage mechanisms, damage control methods and remedy methods in case damage occurs.
A more speci c programme of data gathering and analysis can be carried out once an injectivity problem has been detected by these screening tools. Techniques such as a well pressure fall-off test or a step-rate injectivity test can be used to derive fracture initiation, propagation and closure pressures, as well as detect the presence of a well skin or more distant geological features, such as faults and channels that may affect the injection pressure. Production logging (e.g. spinner or temperature survey) can indicate the injection pro le. More specialized methods, such as hydraulic impedance testing, tiltmeter mapping and micro-seismic tests can be used to estimate the dimensions of water ood induced fractures (Holzhausen and Egan, 1987; Paige et al., 1994). Instrumentation for the monitoring of the water treatment plant performance by measuring the concentration of solids and dispersed oil in the injection stream at surface is available. Particle size distribution and concentration have
frequently been measured using a Coulter counter or Malvern particle analyser. They experience dif culties in differentiating between oil droplets and solid particles and have a tendency to over-estimate the size of particles with irregular shape. These uncertainties and the use of different analytical techniques often give signi cantly different results when the same uid is analysed (Todd, 2003). Recent developments in on-line water quality monitoring techniques have included application of pulsed photoacoustics (Schanke et al., 2001) and video=microscope image analysis techniques (Nezhati et al., 2000). These methods have the potential of providing more accurate measurements at a reasonable cost by differentiating between up to seven particle or oil droplet types (Schanke et al., 2001). The ability to use their different particle shapes to identify types of solid particles, such as formation nes, crystallized minerals (scale), bacteria or corrosion products
Figure 5. Suspended solids in the Ula water injection system (Clifford et al., 2001). The injection water picked up iron particles from the injection owlines and the water quality is signi cantly worse down-hole.
Figure 6. The value of an oil eld is increased by accelerating and enhancing the hydrocarbon production. This additional value represents the value of the injection water.
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Figure 7. The water injection scheduling: (a) should the injectivity decline be accepted and future requirements met with new wells (low cost wells, delay capital expenditure, improve design based on previous experience)? (b) Should the wells be regularly stimulated (back ow, hydraulic fracturing, acid wash or injection of acid, solvents or other chemicals)? What will be the long-term ef ciency and the total cost involved? (c) Or should the facilities be designed for better water quality from start? That may increase the up-front expenditure, as well as operating costs, but will result in less risk of operational failure and extensive workovers.
as well as to measure the oil droplets would have great advantage when identifying the underlying causes of injectivity problems. Full analysis of the injection water quality, e.g. for dissolved gases or bacteria, is required. Care must be taken that the sample is representative, e.g. the uid properties may change on the way from the collection point to the analysis laboratory or a surface sample may not re ect the downhole conditions. Figure 5 summarizes a case history corrosion caused the downhole solids loading to be higher than the inlet surface water quality (Clifford et al., 1991). An optimum monitoring strategy should be developed using a ‘holistic approach’, identifying the key variables for the speci c case under consideration and maximizing the available information at minimum cost. Maximum use should be made of the data once it has been gathered using the various proven analysis techniques, e.g. superimpose the results from the water treatment plant performance analysis on the (sand face) pressure-rate plot to identify how sensitive the well performance is to operational upsets in the injection system. Any well injectivity damage should be analysed bearing in mind the recorded variations in injection water properties.
WATER INJECTION ECONOMICS Today’s economic environment requires oil companies not only to consider water injection as a ‘cost’, but as an operation generating additional value to the asset. Water injection studies should focus at methods to improve the value of the injection water. A successful water ooding operation may accelerate hydrocarbon production and possibly increase and extend the plateau rate of the production pro le. However, the biggest bene ts come through enhanced post-plateau production or secondary recovery (Figure 6). Both the earlier production and improved overall recovery will add to the value of the overall eld development. The difference in the
eld value with and without water ooding represents the value of the injection water. A degree of down-hole, formation plugging due to contaminants (oil and solid particles) is normally accepted as a practical, economic compromise. Quanti cation of the degree of damage attributable to a particular type of contaminants in the injection water allows it to be set against the potential loss or delay in oil production due to a reduced injection rate. This can then be balanced against savings in water ltration and de-oiling treatment costs. Reliable injectivity prediction methods and an understanding of the uncertainties involved are essential for any water injection planning or operational decisions, e.g. (1) whether an injectivity decline should be accepted (Figure 7a); (2) what type and how frequently a stimulation or other remedial treatment should be used (Figure 7b); or (3) if the injection system should be designed differently from start to reduce the risk of injectivity decline (Figure 7c). The underlying message is that careful planning of the water injection scheme during the eld developmentstage will most likely be less costly than alterations later in the eld life. The economics of these options should be analysed and compared for the particular production circumstances at an early stage in the project cycle when they are all technically viable. They may need to be reviewed at regular intervals as new information on the injection operation becomes available. Example Application of an Integrated Technical and Economic Model It will have become clear that high and sustained injection well performance is the key to achieving a low-cost water injection project. The picture becomes more complex when a choice has to be made between various water sources, each with associated capital (CAPEX) and operating (OPEX)
Table 3. Water quality properties of the different injection water options. NB., the injectivity index at time zero (II0) will be lower for the more viscous, lower-temperature water sources. Water source SW AW PW AW ‡ PW
Surface temperature
Viscosity
Injectivity index
Solids concentration
Particle size
10¯ C 30¯ C 80¯ C 55¯ C
1.17 cp 0.81 cp 0.38 cp 0.54 cp
230 bpd=psi 332 bpd=psi 708 bpd=psi 498 bpd=psi
3 mg l¡1 1 mg l¡1 9 mg l¡1 5 mg l¡1
1 mm 1 mm 5 mm 4.5 mm
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Half-life 57 172 19 34
days days days days
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Figure 8. Injectivity as a function of time based on McCune’s model for various injection water sources. The vertical lines indicate when acid stimulation treatments have removed the formation damage and returned the well to its original injectivity index.
expenses along with various environmental bene ts. The bene ts and costs associated with the various options can be explored if a integrated technical and economic model is constructed. The following example uses McCune’s injectivity prediction model (Bayona, 1993) to predict injectivity behaviour of the different water sources available for water ood operation in a typical North Sea oil eld. This eld is currently injecting SW, which has been found to give unacceptable scaling problems (Anderson, 2000). The results are presented in Table 3 and Figure 8. Figure 8 shows that all the water sources cause well injectivity to decline with time and regular acid stimulation treatments are required to achieve the target injection
volume. AW has the least impact, requiring one acid stimulation treatment per year. The PW’s higher solids and oil loading is predicted to require at least four acid stimulation treatments each year to reach the same injected water volume target. An economic cost model was set up which allowed the incremental cost elements associated with either continuing with an improved SWI operation (monitoring, water treatment and regular workovers) or implementing AWI or AW=PWI process. Table 4 summarizes the input data and the model results. Note, it has been assumed that PWI requires little additional expenditure as treatment facilities for offshore disposal are already in place. However, a
Table 4. Cost elements involved when changing water injection scheme, presented in terms of cost in US$ per bbl of total daily injection rate (20,000m3 day¡1). Cost elements
SWI
AWI
AWI ‡ PWI
Incremental CAPEX: Increased well cost [AW producer(s) required] Increased treatment equipment cost (AW treatment equipment is required) Increased injection pump cost (need increased pumping power for PW) Incremental OPEX=bbl over base case (scaling SWI)
$0 $0 $0
$2,500,000 $6,000,000 $500,000
$1,750,000 $3,000,000 $250,000
$0
$0
$500,000
$0.245
$0.172
$0.125
Incremental ‘average’ pump cost=bbl Incremental chemical injection (SW, scale and corrosion inhibitors; and AW, corrosion inhibitors)=bbl Plant maintenance (SW, scale removal; AW, corrosion; PW, erosion)=bbl AW lifting ($0.06=bbl AW) Increased monitoring effort (water quality, injection pro le and injection performance)
$0.004 $0.200
$0.004 $0.100
$0.011 $0.075
$0.040
$0.020
$0.015
$0.000 $0.001
$0.047 $0.001
$0.024 $0.001
10,000m3 day¡1 10,000m3 day¡1 20,000m3 day¡1
10,000m3 day¡1 10,000m3 day¡1 20,000m3 day¡1
10,000m3 day¡1 0 m3 day¡1 10,000m3 day¡1
Tubing replacements (SW, 4 years; AW, 5 years; PW, 3 years): $200,000 each Acid stimulation per well (SW, 2=year; AW, 1=year; AW ‡ PW, 4=year): $50,000 each SWI, 2 injectors; AWI, 2 injectors and 2 AW producers; AW=PWRI, 2 injectors and 1 AW producer Total volume of produced water processed: Total volume of water disposed overboard: Total volume of injection water prepared:
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THE WATER INJECTION PROCESS signi cant additional cost for AW supply will be incurred. The potential of a lower operating cost and a reduced Environmental Impact associated with mixed AW=PWI, based on the created scenario, can be seen from Table 4. CONCLUSIONS (1) Water injection is an essential element in modern oil eld operations for adding value to the asset. Technical and economic aspects of water injection are now of equal importance as the more traditional facets of oil eld planning and operation. (2) Subsurface disposal of produced water has been common practice for many years on shore. Produced water (re)-injection is a technology that addresses the economic, environmental and sustainability issues associated with offshore operations. It is more complex and may often be operated within tighter economic margins than a fresh, sea or aquifer water injection project. (3) Many parameters impact the performance of a water injection project. Integration of the key technical and economical elements allows the development of a holistic approach to the water injection process. This has been illustrated by an example case study. (4) The above process not only assigns a quantitative value to each volume of injection water, but also provides a quantitative framework against which day-to-day decisions concerning operation of the water ood plant and process can be made. NOMENCLATURE Af Am ds h II0 Xf
formation surface area of a fractured injection well, m2 formation surface area of a matrix injection well, m2 well diameter, m formation thickness, m ‘undamaged’, initial injectivity index, m3 day¡1bar, or bpd psi¡1 fracture half-length, m
REFERENCES Anderson, K.J., et al., 2000, Water management in closed loop – problems and solutions at Brage Field. Paper SPE 65162, presented at the SPE European Petroleum Conference, Paris. Bakke, S., et al., 1995, Produced water re-injection (PWRI)—Experiences from the Ula Field, in Produced Water 2. Proceedings from the 1995 International Seminar on Produced Water, Trondheim, Norway, 25–28 September (Plenum Press, New York). Bayona, H.J., 1993, A review of well injectivity performance in Saudi Arabia’s Ghawar eld seawater injection program. SPE 25531, in The SPE Middle East Oil Technical Conference and Exhibition, Bahrain. Clifford, P.J., Mellor, D.W. and Jones, T.J., 1991, Water quality requirements for fractured injection wells. SPE 21439, in SPE Middle East Oil Show, Bahrain. Davies, C.A., 1972, The theory and practice of monitoring and controlling dump oods. SPE 3733, in SPE European Spring Meeting, Amsterdam, The Netherlands. Eden, B., Cousins, T. and Lower, T., 2001, Subsea Rawwater Technology & Economics (The Rawwater Engineering Company). Fambrough, J.D., Lane, R.H. and Braden, J.C., 1995, A comprehensive approach for stimulating produced water injection wells at Prudhoe Bay, Alaska. SPE 28976, in SPE International Symposium on Oil eld Chemistry, San Antonio, TX. Hjelmas, T.A., et al., 1996, Produced water re-injection: experiences from performance measurements on Ula in the North Sea. SPE 35874, in SPE International Conference on Health, Safety and Environment, New Orleans, LA.
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Holzhausen, G.R. and Egan, H.N., 1987, Detection and Control of Hydraulic Fractures in Water Injection Wells. SPE 16362, Applied Geomechanics. McKay, G., et al., 1998, Harding—a eld case study: sand control strategy for ultra high productivity and injectivity wells. SPE 48977, in SPE ATCE, New Orleans, LA. Morita, N., Davis, E. and Whitebay, L., 1998, Guidelines for solving sand problems in water injection wells. SPE 39436, in The 1998 SPE International Symposium on Formation Damage Control, Lafayette, LA. Moschovidis, Z.A., et al., 1998, The mounds drill cuttings experiment: determining placement of drill cuttings by hydraulic fracturing injection. SPE 48987, in SPE Annual Technical Conference and Exhibition, New Orleans, LA. Moschovidis, Z., et al., 2000, The mounds drill-cuttings injection eld experiment: nal results and conclusions. SPE 59115, in 2000 IADC=SPE Drilling Conference, New Orleans, LA. Nezhati, D.K., Roth, N. and Gaskin, R., 2000, On-line determination of particle size and concentration (solids and oil) using ViPA analyser—a way forward to control sub sea separators, in 7th Annual International Forum—Production Separation Systems, Oslo, Norway. Paige, R.W. and Sweeney, F.M., 1993, Produced water re-injection— understanding the problems, in The Water Management Offshore Conference. Paige, R.W., Murray, L.R. and Roberts, J.D.M., 1994, Field Application of Hydraulic Impedance Testing for Fracture Measurement, SPE 26525. Paige, R.W., et al., 1995, Optimising water injection performance. SPE 29774, in The SPE Middle East Oil Show, Bahrain. Palisch, T.T., Grif n, L.G. and Weng, X., 1996, Proppantless fracture stimulation in injection wells–a case history. SPE 35697, in The Western Regional Meeting, Anchorage, AK. Perkins, T.K. and Gonzalez, J.A., 1985, The effect of thermoelastic stresses on injection well fracturing. SPE 11332, SPE J, February. Santarelli, F.J., et al., 1998, Sand production on water injectors: just how bad can it get? SPE=ISRM 47329, in The SPE=ISRM Eurock ’98, Trondheim, Norway. Schanke, T., Kjølberg, S.A. and Vogel, F., 2001, Oil in water monitoring for subsea and downhole separators. SPE 66538, in SPE=EPA=DOE Exploration and Production Environmental Conference, San Antonio, TX. Sharma, M.M., et al., 2000, Injectivity decline in water-injection wells: an offshore gulf of Mexico case study. SPE 60901, in SPE Production and Facilities, February. Stevens, D.G., Murray, L.R. and Shah, P.C., 2000, Predicting multiple thermal fractures in horizontal injection wells; coupling of a wellbore and a reservoir simulator. SPE 59354, in The 2000 SPE=DOE Improved Oil Recovery Symposium, Tulsa, OK. Todd, A.C., 2003,> Core Flooding as Related to Water Injection (in press). Todd, A.C., Somerville, J.E. and Scott, G., 1984, The application of depth of formation damage measurements in predicting water injectivity decline. SPE 12498, in The SPE Formation Damage Control Symposium, Bakers eld, CA. van den Hoek, P.J. and McLennan, J.D., 2000, Hydraulic fracturing in produced water reinjection, in The Workshop on Three-Dimensional and Advanced Hydraulic Fracture Modeling, held in conjunction with the Fourth North American Rock Mechanics Symposium, Seattle, WA. van der Zwaag, C. and Øyno, L., 1996, Comparison of injectivity prediction models to estimate Ula Field injector performance for produced water reinjection, in Produced Water 2: Environmental Issues and Mitigation Technologies, Reed, M. and Johnsen, S. (eds) (Plenum Press, New York). Warren, E.A. and Smalley, P.C., 1994, North Sea Formation Water Atlas (The Geological Society, London).
ACKNOWLEDGEMENTS The authors are pleased to acknowledge the nancial support provided to one of the authors (Bjarni Palsson) by the many oil companies who sponsored the Produced Water Re-Injection Joint Industry Project and by Schlumberger.
ADDRESS Correspondence concerning this paper should be addressed to Dr D. Davies, Department of Petroleum Engineering, Heriot-Watt University, Research Park, Riccarton, Edinburgh EH14 4AS, UK. E-mail: [email protected] The manuscript was received 30 October 2002 and accepted for publication after revision 31 January 2003.
www.ingentaselect.com=titles=02638762.htm
THE WATER INJECTION PROCESS A Technical and Economic Integrated Approach B. PALSSON, D. R. DAVIES, A. C. TODD and J. M. SOMERVILLE Heriot–Watt University, Edinburgh, UK
W
ater injection is an essential part of many modern oil eld development plans. Highcost offshore developments require that the water ood process equipment is designed and installed prior to acquiring any injection experience on that particular eld. The chosen design must not only maximize the oil production revenue, but also carry an acceptable level of risk in terms of the project costs and technical uncertainties. This paper describes a holistic approach for an economic evaluation of the water injection process, integrating the key technical and economical elements. Well injectivity, which describes the well-to-reservoir connection, is a central factor in any water injection operation. The formation characteristics, water properties, well con guration and the injection water pressure determine this. Injection well behaviour is dominated by fracture geometry if the well is operated at suf ciently high pressure. By contrast, the injectivity of a well operated under matrix conditions (below fracture pressure) is dominated by formation damage caused by impurities in the injection water. This paper highlights the role of well injectivity provides a quantitative framework and a worked example of how decisions concerning design and operation of the water ood plant, process and wells can be made. Keywords: water injection; well injectivity; formation damage; environmental impact; techno-economics.
recovery and increases the water handling costs. This will have a severe impact on the potential project pro tability, as well as adding to the general uncertainty in eld performance. This paper describes a holistic approach for modern water injection management. It shows how the value of water injection can be estimated and provides an economic framework for the evaluation of the water injection process by integrating the key technical and economic elements.
INTRODUCTION Water injection is a key element in modern oil eld operations. Many offshore oil eld development plans call for water injection into the oil reservoirs for water ooding (sweeping the oil to the producers) and for pressure support ( lling the voidage left by the produced uids); often maintaining the reservoir pressure and well bottomhole owing pressures above the bubble point. Other objectives can also become important in speci c situations, e.g. control of rock compaction etc. A successful water injection scheme can therefore lead to optimum eld development by:
TECHNICAL CHALLENGES WITH WATER INJECTION
(1) maximizing overall recovery—an evenly distributed waterfront sweeps the hydrocarbons towards the producers; (2) accelerating hydrocarbon production by maintaining high reservoir pressure; (3) minimizing water production and the associated water handling cost; and (4) minimizing the projects environmental impact [e.g. halt surface disposal of produced water by its (re)injection into the reservoir].
The main objectives of water injection well operation are to: (1) achieve and sustain the required injection rate with minimum cost (the sum of well, water treatment, pump, workover costs etc.); (2) control the water injection pro le to maximise the sweep ef ciency (e.g. avoid plugging of tight zones and contain water ood induced fractures within the injection zone); and, ultimately, (3) reduce the uncertainty in the expected well injectivity, allowing for more accurate production planning to ensure that project economic objectives are met.
An unsuccessful water injection scheme, resulting in limited reservoir pressure support, poor sweep ef ciency and excessive water production, reduces the overall oil 333
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Many factors contribute to the success of a water ood operation. However, well injectivity can be referred to as the central factor, indicating how much pressure has to be applied to achieve a certain injection rate for given well and formation characteristics, as illustrated in Figure 1. The top triangle in Figure 1 presents the factors affecting well injectivity, such as injection water source, properties and treatment, injection pump capacity and well issues. The lower triangle represents the water ood factors that may be affected by well injectivity, such as the injection pro le, fracture conformance, near-wellbore reservoir cross ow, reservoir pressure support and sweep ef ciency of hydrocarbons. Study of the expected well injectivity is therefore the fundamental technical factor for any water injection system, both at the planning and the operational stages. The latter is especially important as monitoring the performance of injection wells and the treatment plant performance allows modi cations to the injection strategy as a response to changes in well injectivity.
Water Characteristics The properties of the injection water are one of the most important factors in de ning the injectivity. ‘Water Quality’ is determined by the source of the injection water and its treatment prior to injection. Four classes of water injection schemes are encountered in oil eld operations: (1) Surface fresh water injection (SFWI)—the surface water is generally taken from rivers or lakes and is therefore likely to be rich in oxygen and organic matter. SFWI is increasingly uncommon since in most parts of the world surface water is considered too valuable. (2) Sea water injection (SWI)—SWI is the most common option in offshore and coastal environments. The sea water contains traces of both suspended and dissolved minerals, oxygen and bacteria and is therefore often ltered and treated with chemical doses prior to injection to avoid corrosion, bacteria growth and souring.
The properties of the sea water vary greatly depending on the eld location (estuary, river mouth, shallow or deep water, time of year, etc.). Recent developments of raw water injection (RWI) have taken another approach, installing a satellite plant at the seabed for minimum water treatment and injection into wells constructed from corrosion resistant material (Eden et al., 2001). (3) Aquifer water injection (AWI)—aquifer water is a common alternative where sea water is either not available or is incompatible with the injection formation. A special case of AWI is dump ood injection (DFI), where a single well connects the aquifer and injection zones (Davies, 1972). (4) Produced water injection (PWI)—the increasing volume of water co-produced with the oil stream is either injected into a dedicated disposal zone or re-injected into the producing zone. The traces of oil and other chemicals in the produced water make ltration dif cult and the injection operation is therefore more complicated. Recent developments of subsea separation and (re)-injection (SSI) and down-hole oil–water separation (DHOWS) and re-injection are other forms of PWI. The key characteristics of the water injection schemes, such as the concentration of total suspended solids (TSS), total dissolved solids (TDS), oil-in-water (OIW) suspensions and solid particle size (ds), are summarized in Table 1. Table 1 shows the advantages of ‘clear water’ (AW and SW). PWI is, however, rapidly becoming the process of choice to help minimize the eld’s environmental impact. The PW will still contain traces of oil, as well as numerous dissolved or suspended minerals and other organic species. Residues from the various production chemicals injected in the production wells or added in the surface facilities will also be present. The chemical and physical properties of PW and SW for the Prudhoe Bay eld in Alaska and the Ula eld in the Norwegian North Sea are listed in Table 2. Note the varied ion makeup of the different water sources, making generalizations between elds dif cult.
Figure 1. The pivotal role of well injectivity in the water cycle ef ciency. PW, produced water; SW, sea water; AW, aquifer water.
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Environmental issues, organic material Corrosion products, low temperature can cause TIFa Often compatible with connate water Sanding (affects injection), limits in monitoring Minimum SW treatment, corrosion, organic material Large solids, organic material, production chemicals Less chance of PW being exposed to atmosphere Less pressure variation than PWRI, dif cult without access
The main objective of injection well design is to optimize the connection to the injection zone formation. The key technical challenges are to:
Varies Small Small (varies) Small (varies) Medium Large? High? Medium?
None None None None None Medium Medium High
Varies High Medium Medium High High High High
(1) achieve and sustain the required injection rate; (2) control the water injection pro le to maximize the sweep ef ciency; and (3) reduce the uncertainty in the expected injection well operation.
Varies Medium (varies) Low (varies) Low (varies) High High High? High? Thermally induced fractures (TIF).
a
Onshore Offshore Onshore=offshore Onshore (offshore?) Offshore Onshore=offshore Offshore Onshore (offshore?) SFWI SWI AWI DFI RWI PWI SSI DHOWS
335 Well Characteristics
Proven—successful Proven—successful Proven—successful Proven—successful? In development Mixed results In development In development
TDS OIW ds TSS Application Process
Status of technology
Water quality
Table 1. Summary of the key issues for the main water injection schemes.
Comments
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The well characteristics that have an impact on well injectivity include well deviation and orientation, completion ef ciency and the near-wellbore effects, e.g. drilling and completion damage. Water injection completions are generally designed with the objectives of withstanding high injection pressure and minimizing maintenance costs, e.g. tubing replacements. As for production wells, open-hole completion will provide the best wellbore connection, but selective perforating procedures are often applied where zonal isolation is required. The development of zones with different pressure regimes, connected by the same (injection) wellbore, leads to allocation problems when monitoring the water ood progress. This problem becomes more severe when the well is shut in due to the larger water volumes involved. From a well operation point of view, injection wells in unconsolidated formations, which may be stable during injection, become prone to sand production during cross ow when the well is shut in, resulting in loss of the well due to sanding in the wellbore. Suitable sand control measures need to be in place (Santarelli et al., 1998; Morita et al., 1998; McKay et al., 1998). Most types of sand control completions limit the in ow area and are prone to erosion and particle plugging. Hydraulic fractures have been applied in certain situations to improve the well-to-reservoir connection, especially in tight formations. Propped fractures appear to plug more quickly and result in poorer injectivity performance than non-propped fractures (Palisch et al., 1996). Injection above fracture pressure, resulting in a continuously propagating water ood-induced fracture, has obvious bene ts (Figure 2). A fractured injector has a fundamentally different leak-off mechanism from a non-fractured (matrix) injector, since the fracture has a large formation surface area exposed to the injection water. The fracture also has a large storage capacity for the suspended particles that may be ltered out and will also continuously open up further undamaged (‘clean’) formation at the fracture tip, if the fracture can propagate. To illustrate these differences, a ‘typical’ North Sea injection well, with a 7 inch open hole completion in a 100 m thick interval, has a surface area of 56 m2, whereas a water ood-induced fracture with a half-length of 30 m has effective wellbore of 12,056 m2 or 215 times larger. Injection of 4000 m3 day¡1 (25,000 bpd) of the produced water from the Ula eld (Table 3, TSS ˆ 22 mg l¡1) will carry approximately 90 kg day¡1 of solids; or about 16 m3 year¡1, into the well. If the solids are assumed not to invade the formation and have a solids= lter-cake density of 2000 kg m¡3, there is suf cient volume to ll the matrix wellbore to above the perforations six times during a one year injection period. In contrast, an evenly distributed ltercake on the fracture walls would have a thickness of only
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Table 2. Chemical and physical properties of injection water in two oil elds. Field Prudhoe Bay (Fambrough et al., 1995) Water source Component concentration (mg l¡1) Total suspended solids (TSS) Total lterable solids Mean particle diameter Total oil-in-water (OIW) Temperature (T) pH Density Total dissolved solids Cations sodium (Na‡ ) potassium (K‡ ) magnesium (Mg2‡ ) calcium (Ca2‡ ) strontium (Sr2‡ ) barium (Ba2‡ ) iron (Fe2‡ or Fe3‡ ) Anions chloride (Cl¡) sulphate (SO42) bicarbonate (HCO3¡) Gases free carbon dioxide (CO2) oxygen Bacteria sulphate-reducing bacteria general aerobic bacteria Dissolved hydrocarbons
Ula (Bakke et al., 1995; Hjelmas et al., 1996; van der Zwaag and Øyno, 1996)
PW
SW
IW (65%SW, 35%PW)
PW
N=A 10–15 mg l¡1 N=A 400–600 mg l¡1 N=A 6.8 1019kg m¡3 N=A
4 mg l¡1 N=A 3 mm 0 mg l¡1 18¯ C 8.1 1023 kg m¡3 N=A
6 mg l¡1 22 mg l¡1 N=A 15 mg l¡1 31¯ C 7.3 1035 kg m¡3 N=A
22 mg l¡1 48 mg l¡1 N=A 39 mg l¡1 39¯ C 6.8 N=A 247,107a
8780 mg l¡1 135 mg l¡1 353 mg l¡1 287 mg l¡1 20 mg l¡1 1 mg l¡1 N=A
N=A N=A N=A 410 mg l¡1 8 mg l¡1 0 mg l¡1 0 mg l¡1
N=A N=A N=A 2330 mg l¡1 96 mg l¡1 5 mg l¡1 11 mg l¡1
52,225a 3507a 2249a 6255 mg l¡1 267 mg l¡1 23 mg l¡1 30 mg l¡1
13,200mg l¡1 785 mg l¡1 2350 mg l¡1
19,850mg l¡1 2790 mg l¡1 140 mg l¡1
28,300mg l¡1 1900 mg l¡1 192 mg l¡1
43,700mg l¡1 463 mg l¡1 208 mg l¡1
N=A N=A
7 mg l¡1 80 mg l¡1
52 mg l¡1 15 mg l¡1
175 mg l¡1 0 mg l¡1
N=A N=A N=A
0 count ml¡1 45 count ml¡1 1 mg l¡1
5 count ml¡1 200 count ml¡1 8 mg l¡1
N=A N=A 19 mg l¡1
a
Formation water properties (Warren and Smalley, 1994).
1.4 mm. If the solids did invade the formation, the volume of solids injected each year is suf cient to ll all pores 42 cm into the formation for a matrix well but only 7 mm into the formation surrounding a water ood induced fracture (assuming 20% porosity). Laboratory experiments show that matrix injection (Figure 2a) is dominated by particle plugging (Todd et al., 1984). All matrix injectivity prediction models will therefore predict a large, but smooth, injectivity decline; even for injection of relatively clean sea water into a permeable sandstone (Figure 3a; Sharma et al., 2000). Injection under the condition of thermally=water ood-induced fracturing (Figure 2b) is, however, quite different. Injectivity is generally better sustained and changing from injection of cold SW to warm PW leads to an abrupt reduction in injectivity to a lower level where it remains reasonably constant (Figure 3b; van den Hoek and McLennan, 2000). Injection of water considerably colder than the receiving formation will cool the near-wellbore rock and cause localized stress reduction. This ‘thermally induced fracturing’ (TIF) causes a hydraulic fracture to form at a lower injection pressure than would normally be expected (Perkins and Gonzalez, 1985). A fracture will only be created in the ooded zone, and will be contained within it, if cold water is injected below the in-situ=far- eld stress but above the thermally lowered stress. This reduces the risk of out-ofzone fracturing (Morita et al., 1998). This has been used as a fracture containment procedure when injecting into a new well for the rst time (Stevens et al., 2000).
There are many publications discussing various aspects of thermally induced fractures—it has even been claimed that most water injectors are thermally fractured (Paige and Sweeney, 1993). A multi-well study of the Prudhoe Bay eld performance showed that long-term injection of SW at bottom-hole injection pressure above the thermally lowered formation stress resulted in stable injectivity (Paige et al., 1995). When converted to (warmer) PW, with its higher solids and dispersed oil loading, the injectivity declined rapidly to a lower ‘plateau’ level where it continued to decline slowly (Figure 3b). If the temperature and particle loading are high, the plateau level will be lower and the injectivity decline will be faster. When converted back to
Figure 2. Illustration of the fundamental differences between a non-fractured=matrix (left) and fractured (right) injectors: leak-off area, leak-off mechanism ( ow velocity and direction) and the storage capacity.
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Figure 3. (a) Injectivity decline due to injection of ltered SW under matrix conditions in a Gulf of Mexico eld (permeability 1–4 darcy; Sharma et al., 2000). (b) Injectivity of un ltered SW and PW in an injector with water ood-induced fracture; the Forties eld, well A5-3 (Paige et al., 1995).
cold sea water, the initial injectivity was quickly restored. It has been observed that the well deviation and orientation have a signi cant impact on the fracture propagation pressure when there is a signi cant contrast between the minimum and maximum horizontal stresses (Paige et al., 1995). Modelling of fractured well water injection continues to be a major technical challenge. Many models are capable of matching the observed injectivity but do not describe adequately what happens to the injected solids (van den Hoek and McLennan, 2000). Injection of the Prudhoe Bay PW (Table 2) with a TSS of 15 mg l¡1 at an average rate of 1200 m3 day¡1 (7500 bpd) for 10 years delivers 32.6 m3 of solids into the wellbore. If we assume that the fracture height equals the pay thickness (10 m) and that average fracture width is 5 mm, then the fracture half-length has to be at least 325 m (approximately 1000 ft) if all the solids are stored in a single, narrow fracture. This is a signi cantly longer fracture than standard fracture monitoring methods, such as pressure fall-off tests or hydraulic impedance tests would indicate (van den Hoek and McLennan, 2000). This is a small volume of solids compared with that injected into wells during cuttings re-injection operations (Moschovidis et al., 1998). Rock mechanical models have recently been proposed to account for these large volumes (van den Hoek and McLennan, 2000; Moschovidis et al., 2000). Operational Aspects Once the injection system is installed, alterations to the injection pump power (pressure and ow rate) and the water treatment ef ciency are the most easily adjustable parts of the operation. If injectivity decline occurs, the injection pump pressure can be increased to maintain the required injection rate. However, the injection pressure may be limited by the pump power, well and completion design or by formation issues, e.g. to avoid or limit fracture growth. Impurities in the injection water, such as dissolved minerals, gases and (organic) chemicals as well as suspended particles, are the biggest contributors to injectivity damage. Most sources of water require some form of treatment prior to injection, e.g. chemical dosing, ltration, separation etc. Such water treatment is costly and complete puri cation is impractical. Therefore, a compromise has to be made between the chance of formation damage occurring and the overall impact of the potential damage and the Trans IChemE, Vol 81, Part A, March 2003
remedial options against the cost of more extensive water treatment. A roadmap (Figure 4) has been developed which describes the water quality vs injection damage interrelationship. This lists the main sources of injection damage, the key damage mechanisms as well as how they can be controlled and remedied once damage has occurred. Application will, of course, require making it case-speci c. Figure 4 shows that most of the chemical damage processes are relatively easily controlled if the surface water treatment process plant has been speci ed correctly. By contrast, removal of formation injectivity damage can be more problematic. Further, it is technically impractical to fully remove all solids and dispersed oil from the PW. An economic compromise has to be made between PW treatment options and costs, guided by models or other prediction methods of injection well performance.
Monitori ng Monitoring of the injection system and the downhole injectivity performance is essential to recognize controlling mechanisms and to allow quick response if injectivity damage occurs. Analysis of injection performance also provides valuable information to improve future injection system designs. Water injectivity monitoring is commonly limited to the measurement of the wellhead pressure and injection rate at regular, often widely separated, time intervals. Various graphical methods are used to present the well injectivity performance, e.g. (1) pressure-rate plots; (2) plots of pressure and rate against time; (3) injectivity index or reciprocal injectivity index against time; (4) cumulative injection volume against time; or (5) Hall plot etc. Such plots can identify changes in well injectivity, e.g. (1) an injectivity decline can be due to geological reasons (faults, channelling etc.), a fracture closing or formation damage build-up; (2) an injectivity increase can be caused by a fracture opening, fracture extension or fracturing out-of-zone.
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Figure 4. Source of water injection damage, damage mechanisms, damage control methods and remedy methods in case damage occurs.
A more speci c programme of data gathering and analysis can be carried out once an injectivity problem has been detected by these screening tools. Techniques such as a well pressure fall-off test or a step-rate injectivity test can be used to derive fracture initiation, propagation and closure pressures, as well as detect the presence of a well skin or more distant geological features, such as faults and channels that may affect the injection pressure. Production logging (e.g. spinner or temperature survey) can indicate the injection pro le. More specialized methods, such as hydraulic impedance testing, tiltmeter mapping and micro-seismic tests can be used to estimate the dimensions of water ood induced fractures (Holzhausen and Egan, 1987; Paige et al., 1994). Instrumentation for the monitoring of the water treatment plant performance by measuring the concentration of solids and dispersed oil in the injection stream at surface is available. Particle size distribution and concentration have
frequently been measured using a Coulter counter or Malvern particle analyser. They experience dif culties in differentiating between oil droplets and solid particles and have a tendency to over-estimate the size of particles with irregular shape. These uncertainties and the use of different analytical techniques often give signi cantly different results when the same uid is analysed (Todd, 2003). Recent developments in on-line water quality monitoring techniques have included application of pulsed photoacoustics (Schanke et al., 2001) and video=microscope image analysis techniques (Nezhati et al., 2000). These methods have the potential of providing more accurate measurements at a reasonable cost by differentiating between up to seven particle or oil droplet types (Schanke et al., 2001). The ability to use their different particle shapes to identify types of solid particles, such as formation nes, crystallized minerals (scale), bacteria or corrosion products
Figure 5. Suspended solids in the Ula water injection system (Clifford et al., 2001). The injection water picked up iron particles from the injection owlines and the water quality is signi cantly worse down-hole.
Figure 6. The value of an oil eld is increased by accelerating and enhancing the hydrocarbon production. This additional value represents the value of the injection water.
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Figure 7. The water injection scheduling: (a) should the injectivity decline be accepted and future requirements met with new wells (low cost wells, delay capital expenditure, improve design based on previous experience)? (b) Should the wells be regularly stimulated (back ow, hydraulic fracturing, acid wash or injection of acid, solvents or other chemicals)? What will be the long-term ef ciency and the total cost involved? (c) Or should the facilities be designed for better water quality from start? That may increase the up-front expenditure, as well as operating costs, but will result in less risk of operational failure and extensive workovers.
as well as to measure the oil droplets would have great advantage when identifying the underlying causes of injectivity problems. Full analysis of the injection water quality, e.g. for dissolved gases or bacteria, is required. Care must be taken that the sample is representative, e.g. the uid properties may change on the way from the collection point to the analysis laboratory or a surface sample may not re ect the downhole conditions. Figure 5 summarizes a case history corrosion caused the downhole solids loading to be higher than the inlet surface water quality (Clifford et al., 1991). An optimum monitoring strategy should be developed using a ‘holistic approach’, identifying the key variables for the speci c case under consideration and maximizing the available information at minimum cost. Maximum use should be made of the data once it has been gathered using the various proven analysis techniques, e.g. superimpose the results from the water treatment plant performance analysis on the (sand face) pressure-rate plot to identify how sensitive the well performance is to operational upsets in the injection system. Any well injectivity damage should be analysed bearing in mind the recorded variations in injection water properties.
WATER INJECTION ECONOMICS Today’s economic environment requires oil companies not only to consider water injection as a ‘cost’, but as an operation generating additional value to the asset. Water injection studies should focus at methods to improve the value of the injection water. A successful water ooding operation may accelerate hydrocarbon production and possibly increase and extend the plateau rate of the production pro le. However, the biggest bene ts come through enhanced post-plateau production or secondary recovery (Figure 6). Both the earlier production and improved overall recovery will add to the value of the overall eld development. The difference in the
eld value with and without water ooding represents the value of the injection water. A degree of down-hole, formation plugging due to contaminants (oil and solid particles) is normally accepted as a practical, economic compromise. Quanti cation of the degree of damage attributable to a particular type of contaminants in the injection water allows it to be set against the potential loss or delay in oil production due to a reduced injection rate. This can then be balanced against savings in water ltration and de-oiling treatment costs. Reliable injectivity prediction methods and an understanding of the uncertainties involved are essential for any water injection planning or operational decisions, e.g. (1) whether an injectivity decline should be accepted (Figure 7a); (2) what type and how frequently a stimulation or other remedial treatment should be used (Figure 7b); or (3) if the injection system should be designed differently from start to reduce the risk of injectivity decline (Figure 7c). The underlying message is that careful planning of the water injection scheme during the eld developmentstage will most likely be less costly than alterations later in the eld life. The economics of these options should be analysed and compared for the particular production circumstances at an early stage in the project cycle when they are all technically viable. They may need to be reviewed at regular intervals as new information on the injection operation becomes available. Example Application of an Integrated Technical and Economic Model It will have become clear that high and sustained injection well performance is the key to achieving a low-cost water injection project. The picture becomes more complex when a choice has to be made between various water sources, each with associated capital (CAPEX) and operating (OPEX)
Table 3. Water quality properties of the different injection water options. NB., the injectivity index at time zero (II0) will be lower for the more viscous, lower-temperature water sources. Water source SW AW PW AW ‡ PW
Surface temperature
Viscosity
Injectivity index
Solids concentration
Particle size
10¯ C 30¯ C 80¯ C 55¯ C
1.17 cp 0.81 cp 0.38 cp 0.54 cp
230 bpd=psi 332 bpd=psi 708 bpd=psi 498 bpd=psi
3 mg l¡1 1 mg l¡1 9 mg l¡1 5 mg l¡1
1 mm 1 mm 5 mm 4.5 mm
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Half-life 57 172 19 34
days days days days
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Figure 8. Injectivity as a function of time based on McCune’s model for various injection water sources. The vertical lines indicate when acid stimulation treatments have removed the formation damage and returned the well to its original injectivity index.
expenses along with various environmental bene ts. The bene ts and costs associated with the various options can be explored if a integrated technical and economic model is constructed. The following example uses McCune’s injectivity prediction model (Bayona, 1993) to predict injectivity behaviour of the different water sources available for water ood operation in a typical North Sea oil eld. This eld is currently injecting SW, which has been found to give unacceptable scaling problems (Anderson, 2000). The results are presented in Table 3 and Figure 8. Figure 8 shows that all the water sources cause well injectivity to decline with time and regular acid stimulation treatments are required to achieve the target injection
volume. AW has the least impact, requiring one acid stimulation treatment per year. The PW’s higher solids and oil loading is predicted to require at least four acid stimulation treatments each year to reach the same injected water volume target. An economic cost model was set up which allowed the incremental cost elements associated with either continuing with an improved SWI operation (monitoring, water treatment and regular workovers) or implementing AWI or AW=PWI process. Table 4 summarizes the input data and the model results. Note, it has been assumed that PWI requires little additional expenditure as treatment facilities for offshore disposal are already in place. However, a
Table 4. Cost elements involved when changing water injection scheme, presented in terms of cost in US$ per bbl of total daily injection rate (20,000m3 day¡1). Cost elements
SWI
AWI
AWI ‡ PWI
Incremental CAPEX: Increased well cost [AW producer(s) required] Increased treatment equipment cost (AW treatment equipment is required) Increased injection pump cost (need increased pumping power for PW) Incremental OPEX=bbl over base case (scaling SWI)
$0 $0 $0
$2,500,000 $6,000,000 $500,000
$1,750,000 $3,000,000 $250,000
$0
$0
$500,000
$0.245
$0.172
$0.125
Incremental ‘average’ pump cost=bbl Incremental chemical injection (SW, scale and corrosion inhibitors; and AW, corrosion inhibitors)=bbl Plant maintenance (SW, scale removal; AW, corrosion; PW, erosion)=bbl AW lifting ($0.06=bbl AW) Increased monitoring effort (water quality, injection pro le and injection performance)
$0.004 $0.200
$0.004 $0.100
$0.011 $0.075
$0.040
$0.020
$0.015
$0.000 $0.001
$0.047 $0.001
$0.024 $0.001
10,000m3 day¡1 10,000m3 day¡1 20,000m3 day¡1
10,000m3 day¡1 10,000m3 day¡1 20,000m3 day¡1
10,000m3 day¡1 0 m3 day¡1 10,000m3 day¡1
Tubing replacements (SW, 4 years; AW, 5 years; PW, 3 years): $200,000 each Acid stimulation per well (SW, 2=year; AW, 1=year; AW ‡ PW, 4=year): $50,000 each SWI, 2 injectors; AWI, 2 injectors and 2 AW producers; AW=PWRI, 2 injectors and 1 AW producer Total volume of produced water processed: Total volume of water disposed overboard: Total volume of injection water prepared:
Trans IChemE, Vol 81, Part A, March 2003
THE WATER INJECTION PROCESS signi cant additional cost for AW supply will be incurred. The potential of a lower operating cost and a reduced Environmental Impact associated with mixed AW=PWI, based on the created scenario, can be seen from Table 4. CONCLUSIONS (1) Water injection is an essential element in modern oil eld operations for adding value to the asset. Technical and economic aspects of water injection are now of equal importance as the more traditional facets of oil eld planning and operation. (2) Subsurface disposal of produced water has been common practice for many years on shore. Produced water (re)-injection is a technology that addresses the economic, environmental and sustainability issues associated with offshore operations. It is more complex and may often be operated within tighter economic margins than a fresh, sea or aquifer water injection project. (3) Many parameters impact the performance of a water injection project. Integration of the key technical and economical elements allows the development of a holistic approach to the water injection process. This has been illustrated by an example case study. (4) The above process not only assigns a quantitative value to each volume of injection water, but also provides a quantitative framework against which day-to-day decisions concerning operation of the water ood plant and process can be made. NOMENCLATURE Af Am ds h II0 Xf
formation surface area of a fractured injection well, m2 formation surface area of a matrix injection well, m2 well diameter, m formation thickness, m ‘undamaged’, initial injectivity index, m3 day¡1bar, or bpd psi¡1 fracture half-length, m
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ACKNOWLEDGEMENTS The authors are pleased to acknowledge the nancial support provided to one of the authors (Bjarni Palsson) by the many oil companies who sponsored the Produced Water Re-Injection Joint Industry Project and by Schlumberger.
ADDRESS Correspondence concerning this paper should be addressed to Dr D. Davies, Department of Petroleum Engineering, Heriot-Watt University, Research Park, Riccarton, Edinburgh EH14 4AS, UK. E-mail: [email protected] The manuscript was received 30 October 2002 and accepted for publication after revision 31 January 2003.