2 Number 9, 997 Middle East Well Evaluation Review 3
Excessive water production is a serious issue in many Middle East oil fields. Until recently, efforts to improve water control were hampered by the lack of a diagnostic tool to investigate specific water problems. This meant that many of the solutions put into practice were not addressing the cause of water production. In this article Alan Saxon describes recent advances in candidate recognition and water treatment methods, and shows how these can be used to reduce water cut without damaging oil and gas production
Flowing pressure Production rate Before treatment After treatment Pre-treatment (oil and water) Fig. 5.: The cost of remedial treatment for a well with high water cut must be set against anticipated benefits which will arise from greater production and reduced water handling costs. Graphical analysis of fluid pressures and production rates is an invaluable tool for decision making Excessive water production is one of the main threats to the value of oil and gas wells. It usually means increased production costs and decreasing recovery rates. In the Middle East more than 7 million barrels of water are produced in oil fields every day and this figure is increasing. The volume of water produced by a production well is the most important parameter identifying a potential candidate for water control. Although high water cut is the first indicator of a potential candidate for treatment, the water must be characterized as bad water, that is, water which reduces reservoir pressure, generates additional costs and, in some cases, prevents other oil zones from producing. In some cases, however, wells which only produce oil may have hidden, subsurface water problems. For this reason operators should introduce a more systematic approach to well performance analysis. There are three fundamental questions in water control evaluation: how is water produced at the well? can performance be improved by decreasing produced water volume? is water control treatment justified by field economics? Once water production has been characterized, and the method to improve the well s performance has been selected, economic issues must be considered. The complete economic picture must be reviewed when assessing the potential costs and benefits of water control treatments. The costs associated with direct remedial action for water control must be weighed against the costs of inaction. When a well is experiencing water problems, doing nothing may prove more expensive than dealing with the problem. If no action is taken to reduce water production the operator must consider costs associated with lifting each barrel of oil, surface handling, operational problems (such as deposits, emulsions and sand production) and loss of revenue from deferred productivity. When considering remedial action the potential increase in oil production and reduced water handling costs should be set against the direct cost of treatment. An example is a relatively simple situation where a well was originally producing from two separate layers: if one layer had completely watered out (i.e. was producing bad water) while the other layer was still producing oil, graphical analysis can help the operator to decide whether or not a remedial programme will be cost-effective. On the Nodal plot (Figure 5.) the (orange) line describes the inflow of both layers (oil and water) to the sandface. The green line represents oil influx from one layer while the blue line represents water inflow from the other. The objective of a water control project would be to seal off the watered-out layer. If this was achieved, the water zone would be isolated and there would be an increase in the oil-production rate. In some cases, therefore, the decrease in water handling and production costs may be accompanied by a rise in oil production. The essential components of a successful water management program are: good monitoring to identify problems early and thus allow effective remedial action high-quality treatment design: water problems can arise and be solved in many different ways. The key is choosing the most appropriate solution for the defined problem thorough and critical result evaluation to prevent recurrence. Success and failure In waterflooded fields oil companies strive to increase oil production and improve sweep efficiency. New environmental regulations for reduced water discharge encourage operators to examine their conformance control systems and modify production profiles accordingly. Conformance control during waterflooding includes any technique that reduces water production and redistributes water drive either near the wellbore or deep in the reservoir. Near the wellbore conformance control may involve relatively unsophisticated methods such as setting a bridge plug to isolate part of the well or pumping sand or cement into a well to shut off the bottom perforations. Where there are no barriers to vertical flow close to the wellbore or further out in the formation, water control may be accomplished by gel injection (Figure 5.2). Early water control methods involving direct injection of polymers were tried but proved uneconomic because large volumes were required to alter reservoir behaviour and the polymers were often washed out. The most popular method currently available in the oil field involves gels which, if correctly placed, can deal with the problem much more efficiently using much smaller volumes. Gels are essentially polymer chains which have been linked together by another chemical referred to as a crosslinker. At some trigger condition (typically a specific temperature or ph) the small crosslinking molecules react with two polymer chains simultaneously to link them. This linkage creates a three- 46 Middle East Well Evaluation Review
dimensional tangle of polymer molecules, changing their rheology from a fluid to a rigid gel. The correct chemistry for the polymer treatment is extremely important, but the right chemical in the wrong place will not solve the water production problem and may even make matters worse. Despite the technical advances in polymer treatments, in the most extreme cases of water production the only effective conformance control technique may be to drill a new well in order to drain the structure correctly. Where? when? how? Given that an appropriate polymer gel system can be identified, what other factors determine whether or not a reservoir will benefit from treatment? How should any treatment proceed? Should fluids be placed through injectors or producers? This candidate recognition process is a crucial part of the reservoir engineer s challenge. The most difficult part of the challenge is defining the origin of the water and determining whether or not water from a given interval is necessary for the production of oil. Dangerous mis-diagnosis In the past some treatment programmes have been conducted without an accurate diagnosis of the water problem. This led to extremely variable results from treatments, with occasional dramatic successes interspersed with projects which barely met their water control objectives. In the 980s, for example, many fields were being treated with polymer floods in an effort to control water production. However, without reliable information about water sources, no one could predict which wells were suitable candidates for treatment and which were unlikely to respond. Many candidates and treatments were selected on a best guess basis and, like a doctor prescribing drugs without a thorough diagnosis, the oil industry could not predict the likely results of any treatment. This situation changed in the early 990s with the development of a simple and reliable diagnostic method: water control diagnostic plots. Plotting progress control problems should be rectified before wells or reservoirs are damaged. When a well is in trouble there are some early indications that the reservoir engineer can look for. Careful analysis of well production history and critical logs can guide the engineer in the selection of candidate wells and can point to the source of the problem. Shale Shale Problem control diagnostic plots allow reservoir engineers to identify water production mechanisms using readily available production data. The point of water entry in the well can be located from saturation profiling, flow profiling and porosity from specific logs (e.g. an RST* Reservoir Saturation Tool log or a WFL* Flow Log). Linear plots of water cut versus time have always been used to show the progress and severity of excessive water production. The correlation between water cut (fractional water flow) and average reservoir water saturation for two-phase flow is well known. However, reservoir saturations change with time, so averaging fluid saturation from material balance does not indicate fluid distribution and movement through heterogeneous reservoir formations. (a) (b) (c) Shale Shale Solution Gel Fig. 5.2: There are many solutions for water control. Cementing can be used within the wellbore to shut off aquifer layers (a), but for more complex situations gels may be required to reduce water and increase oil production (b and c) Cement Gelling solution Protective pressure fluid Gel Gelling solution Number 9, 997 47
While basic water-cut plots can show drastic changes, such as sudden well completion failure, the information they provide is very limited. All basic watercut plots are similar, regardless of the problem that is being encountered in the reservoir. Linear or semilog plots have also been used to evaluate recovery efficiency. While useful for evaluation of production efficiency, neither of these plots reveals anything about reservoir flow behaviour. The new diagnostic plots have been generated by conducting a series of systematic water control numerical simulation studies using a black oil simulator. This three-dimensional simulator can model reservoir flow under different drive mechanisms to reveal that derivatives of the water/oil ratio (WOR) plotted against time can be used to differentiate whether the excessive water production problem is due to water coning or multilayer channelling (Figure 5.3). Three periods of WOR development can be seen in this example. During the first stage the WOR curves remain flat indicating expected initial production. This initial WOR value depends on original water saturation, water distribution through the reservoir layers and relative permeability functions. The duration of this first stage depends on the waterdrive mechanism and its termination is marked by the WOR s departure from a constant value. WOR increases during the second stage. The rate of this increase is variable and depends on the water problem. The plots show a clear difference between coning and channelling. The increase is relatively slow for coning and relatively fast for channelling. In the third period and for coning a pseudo-steady state cone develops. The well then produces mainly bottomwater and the cone becomes, in effect, a high water-conductivity channel. The WOR increases rapidly, resembling the results from a channel. At this stage all channelling WOR slopes will be similar because they are mainly controlled by relative permeability. The technique is sufficiently subtle to identify when more than one process is in operation, for example, where bottomwater coning is compounded by latestage channelling (Figure 5.4). Over the past 30 years technical efforts for water control have focused on the development of gels to create flow barriers that suppress water production. Various types of gels were applied in different formations to solve different problems. Using these simple diagnostic plots geoscientists can understand and identify WOR WOR or WOR' 00 0 0. 0.0 0. 00 0 0. 0.0 0.00 WOR WOR' Coning Channelling 0 00 000 0000 Time (days) Fig. 5.3: Diagnostic plots are a quick and reliable way to differentiate water coning from multilayer channelling 0 00 000 0000 Time (days) Fig. 5.4: Bottomwater coning with late-stage channelling. WOR' is the simple time derivative of WOR the mechanisms behind excess water production and select appropriate solutions. The technique concentrates on available production history data and can be used to screen a large number of wells very quickly. Field results have shown that a wide variety of problems can be differentiated through their WOR plots (Figure 5.5 and 5.6). While these diagnostic plots are used primarily for excess water in oil wells, they can also be used to identify gas problems (i.e. a high gas/oil ratio) or to characterize water problems in gas wells. During and after treatment there are a series of checks to assess progress by monitoring injection pressure/rate and the penetration of the treatment fluid. This real-time progress checking allows decisions to be made as soon as anomalies are detected. Tried and tested treatment Once the exact nature of the water problem is known, appropriate water control fluids can be selected for the well. The reservoir engineer s plan for fluid placement will be guided by the diagnostic plots. Careful pre-job simulation using the plots should optimize gel injection and ensure minimal crossflow. WOR or WOR' 0 0. 0.0 WOR WOR' 0.00 0 00 000 0000 Time (days) Fig. 5.5: Field example showing bottomwater drive coning. WOR' is the simple time derivative of WOR WOR or WOR' 00 0 0. 0.0 0.00 0.000 WOR WOR' 0 00 000 0000 Time (days) Fig. 5.6: Field example showing near wellbore water channelling. WOR' is the simple time derivative of WOR control issues can be divided into three main types: open flow paths edge water bottomwater problems. Open flow paths Near-wellbore flow may be caused by poor cement, caving due to sanding or a channel in the formation. The solution may involve the use of cement, gel, resin or stimulation. Fissures between the wellbore and a water layer result in bypassed oil. Excessive water production may be due to the presence of fissures, fractures or faults or to oil being confined to the rock matrix. This type of problem can be remedied at the producer by the application of flowing gel. Fissures to an injector are often linked to areal sweep problems and cause rapid water breakthrough. This problem is identified using tracers and treated at the injector with a gel. Each problem requires specific diagnostic and remedial actions. For example, in near-wellbore channelling the diagnosis may require USI* Ultrasonic Imager tool and WFL logs. Treatment may involve perforating into the water channel and injecting a special KS Chan (995). control diagnostic plots. SPE 30775 48 Middle East Well Evaluation Review
reducing drawdown pressure required for a given rate of oil production producing oil further from the OWC However, when drilling of horizontal drainholes is impractical, the well can be treated with gel. This treatment calls for near-bottom perforations and large injected volumes and can be a very timeconsuming process. Horizontal sidetracks coning Fluid placement The placement of treatment fluids is a major concern. If there is vertical communication between layers (or a poor quality cement sheath) then sealant fluid injected into the watered-out zone could migrate and damage the oil zone. The dual injection technique (Figure 5.8) was developed specifically to prevent this. The dual injection method calls for fluids to be conveyed through coiled tubing (CT). This CT, which contains an electric line. has an inflatable packer placed on it for zonal isolation during treatment. A gamma ray tool and a Casing Collar Locator (CCL) are placed at the bottom of the tubing for accurate depth correlation. The water control gel sealant is pumped down the CT while a protective fluid (e.g. filtered brine or diesel) is pumped between the production tubing and the coiled tubing. Pressure sensors above and below the inflated packer monitor differential pressure across the packer during treatment. If this pressure differential is kept at zero the vertical migration of fluids will be controlled and the placement of sealant gel will be confined to the target zone. Fig. 5.7: Lateral drainholes extend production in reservoirs affected by water coning (ultra-fine) cement or gel to plug it. The choice between special cement and gel usually rests on channel size and location in the formation (e.g. whether or not it is in a fractured interval). Injection pump (gelant) Coiled tubing unit Injection pump (protective fluid) Mixing Edge water Poor areal sweep is common in heterogeneous reservoirs and where fluid fingering occurs. The problem may be treated at the injector by polymer flood, but this approach is often uneconomic. Highly permeable layers, with or without crossflow, present vertical sweep problems. They are usually associated with a waterflood or aquifer layer and the problem is often exacerbated by thief layers and high-permeability streaks. The solution, when there is no crossflow, may be shutting off the layer at the producer or at the injector. This can be achieved mechanically or by gel injection depending on the integrity of the wellbore. Crossflow problems may be solved by shutting off the layer through deep gel penetration. Inflatable packer Bottomwater coning occurs when the well is being produced at or near the oil water contact (OWC). and water production rates depend on the relationship between vertical and horizontal permeability and gel radius. The simplest solution to water coning is to drill laterals from the vertical producer (Figure 5.7). In wells with severe water coning or gravity segregated layer problems, lateral drainholes can be an economic alternative to chemical treatment. Properly placed in the reservoir, a lateral drainhole will prevent coning by: Number 9, 997 Fig. 5.8: Dual injection allows the operator to pump gels into aquifer layers for water control without damaging the reservoir zone. The oil layer is protected by inflatable packers and a protective fluid 49
The acid solution In carbonate reservoirs skin damage is usually removed by stimulation with hydrochloric acid (HCl). The uniform distribution of acid across the appropriate zone is essential for successful treatment. However, achieving efficient diversion of the HCl solution and uniform coverage of the target zone is often hampered by permeability heterogeneity within the treated interval. A new technique recently introduced to the Middle East can divert treatment fluids in carbonate formations. Data from several vertical and horizontal wells in different fields along with pre- and post-treatment production log assessments have indicated the value of this procedure. The new technique uses CT for fluid deployment, and diversion of the treating fluid is accomplished by a temporarily activated crosslinked gelled acid system. This method has been subjected to extensive laboratory results to investigate the exact mechanism by which diversion occurs. Coiled tubing is generally accepted as the best placement method for matrix treatment fluids in both cased and open holes. Bull heading of matrix treatments in carbonate reservoirs usually results in nonuniform treatment, especially in long openhole sections. The effectiveness of particulate diverters in carbonate formations has been questioned by some industry experts and in most instances they cannot be used in conjunction with coiled tubing. Foam is well-established for use in carbonate reservoirs, but requires additional equipment at the wellsite for foam generation. A new diverting agent, originally designed to control fluid loss in acid fracturing treatments, has been adapted for the task. This fluid is an acid-based system which develops a crosslinked gel structure in response to ph changes. The system crosslinks at ph3 to form a firm structure. The crosslinked gel structure starts to break down at ph4 as the acid continues to spend and ultimately the gel has a minimal final viscosity. No particulate solids are involved and formation damage is negligible. A selective campaign of matrix acidizing was introduced to help attain water injection targets in an onshore field in the Middle East. The injection rate for several well clusters had declined, while being supplied with water at a fixed system header pressure of 2000 psi. The Depth (ft) 8380 8390 8400 840 8420 8430 8440 8450 BWPD 0 2000 4000 After Before Zone B Zone A2 Zone A waterflood scheme was an inverted fivespot pattern and the carbonate formation had two separate members, referred to as zones A and B. There were two sets of perforations in Zone A, and Zone B was perforated as a single layer. Many of the field s vertical injector wells were under-performing, achieving only 58% of the daily water injection rate for these clusters. The matrix stimulation method was applied in 9 wells. The acid treatments were based on pre-treatment injection survey results which indicated that Zone B accepted nearly three times more water per foot of perforated interval than Zone A. Across all 9 wells Zone B was taking 64% of the injected water with zones A and A2 accounting for 24% and 2% respectively. The operator decided to place a greater volume of acid in A2, the zone taking least water. The programme called for CT to be placed across Zone B (high water intake), and then treated with acid followed by the diverter. The CT was then moved to A (second highest intake) and the procedure repeated. Finally, zone A2 was treated with a 5% HCl acid blend. The results from Well 5, an offset injector, show a marked improvement in the injection profile (Figure 5.9). Nodal analysis of the same well (Figure 5.0) shows that skin damage was reduced from +5 to 2. Elsewhere in the Middle East, an oil producer and a potential gas injector well in a carbonate formation were treated with a similar matrix technique. A new horizontal well in this field was completed openhole in an oil zone. The well geometry indicated that the horizontal section penetrated the reservoir at a true vertical depth of 8900 ft. The well was drilled to serve as a gas injector and immediately after drilling a bullheaded acid treatment was performed, but the results were unsatisfactory. The well was to be tested for oil production prior to its use as a gas injector and eventually it was planned to inject gas evenly throughout the openhole section. Analysis of the results led reservoir engineers to suspect that the wellbore had been damaged during drilling. A matrix acidizing programme was devised to remove the drilling damage. The well was treated with the 5% HCl Fig. 5.9: Pre- and post-treatment flow profiles from Well 5 show a dramatic improvement in water injection rates A Saxon, B Chariag and M Reda Abdel Rahman (997). An effective matrix diversion technique for carbonate formations. SPE 37734 50 Middle East Well Evaluation Review
acid blend pumped through CT. The temporarily activated crosslinked gelled acid system described in the previous example was used as a diverter. After treatment, the well was flowed and a production log was run. The results indicated a relatively even contribution to oil flow along the horizontal section. Laboratory studies were conducted to simulate the diversion process. Limestone cores with a wide range of permeabilities were placed in a simultaneous dual-flow test apparatus and subjected to the following test sequence: determine permeability of core to brine inject acid to create wormholes and measure acid injection response inject temporarily crosslinked gelled acid to create diversion resume acid injection and evaluate the effectiveness of the diverter. The tests proved conclusively that the diverter produced a reduction in permeability within the cores and that the reduction was more pronounced in cores which had a high initial permeability (Figure 5.). Comparison of pre- and post-treatment flow profiles indicated that a more uniform placement of acid could be accomplished using this method. The technique is flexible and can be applied in oil and water injection wells. Laboratory tests indicated that the temporarily crosslinked gelled acid system could redistribute flow between zones of contrasting permeability. Chemical treatment of water control problems must be guided by sound information about the water source and an assessment of the economic benefits to be derived from any treatment. The application of modern diagnosis techniques for candidate recognition, and new methods which place treatment fluids exactly where they are required, are changing the way conformance is controlled. Permeability (md) Bottomhole pressure (psig) 8000 s=+5 s= 2 6000 WHIP=2000psi 4000 2000 0 0 2000 4000 6000 rate (B/D) 50 40 30 20 0 A B C D 0 0 20 30 40 50 60 Time (minutes) Fluid key: A=2%KCI B=5%HCI C=Diverter D=5%HCL Fig. 5.0: Reduction in skin damage in Well 5 as a result of matrix treatment with diversion system Fig. 5.: Temporarily activated crosslinked gelled acid reduced apparent permeability of two core samples subjected to simultaneous injection. The high permeability core (3mD) shows a greater reduction in apparent permeability than its low permeability (2 md) counterpart Number 9, 997 5