Seawater Injection System Research Articles

Integrating condition-based monitoring with process sensors information for operation and maintenance in a functional modeling framework

Safe operations and adequate maintenance are two main means to achieve reliable production and reduce downtime of a plant. While the tasks of operations and maintenance are carried out by two different groups of staff, as a result, the close relationship between the two tasks is split. In this paper, this challenge is handled by a proposed integrated functional modeling framework. In this framework, the Multilevel Flow Modeling (MFM) method with its cause-consequence reasoning rules is used. Condition-based monitoring is a well-accepted strategy for predictive maintenance and fault detection based on measurements is a well-developed technology for operation support. Information fusion including monitoring conditions of assets and process sensors information for both operation and maintenance in the same modeling framework is desired. The qualitative relationship distribution between operations and maintenance can be established based on the function states of the system. In addition, these relationships are visible for both groups of staff. As a result, the detected information in the early stage of the development of the unpleasant scenarios is used to improve their situation awareness, so that the undesired emergency shutdown from both perspectives of operation and maintenance is prevented. Consequently, it can reduce production loss. A case study of operations and maintenance of a seawater injection system is carried out and shows the industrial applicability of the proposed framework. The case study strongly reveals that there is a highly close relation between operation and maintenance for ensuring the system working properly. It demonstrates that the proposed integrated framework is not only able to support operational tasks but also for the maintenance tasks by including relevant maintenance information of the system. The results show that it can potentially help with decreasing downtime of the system.

Identifying Safety Objectives and Functions for Emergency Shutdown in the Design Phase by Using Functional Modelling

This paper proposes a functional modelling method, called Multilevel Flow Modelling (MFM) for identification of safety objectives and functions of emergency shutdown (ESD) system in the design phase for emergency shutdown safely. Firstly, the required information for designing safety objectives and functions for an emergency shutdown is analysed. The information includes process topology, the initial state of the process, the shutdown objectives, and other constraints, such as design and operational limits of unit operations and hazardous and environmental constraints. Secondly, a procedure is proposed based on the required information by using MFM. The procedure incorporates steps: 1) The MFM model of the process in normal operations are built by following modelling procedures, 2) Initiate states are defined and changing conditions are identified of the process when it shuts down unplanned by using the objective-function tree in the MFM modelling, 3) The goals of the shutdown operation are defined, 4) With the consideration of the shutdown operating goals and changing conditions, the first safety function during shutdown process are identified by using MFM causal reasoning, 5) By using MFM consequence reasoning based on the first identified safety function represented in the MFM model, the rest of the safety functions are identified, and the emergency shutdown procedures are generated. This procedure is demonstrated by designing safety functions in an emergency shut down of a seawater deaeration process in a seawater injection system. The results show that the produced emergency shut down procedure based on the proposed method is feasible and that it can be validated against the real operating procedure.

Corrosion hazards and inhibitor protection in the seawater injection system on the Baltic sea rig

Corrosion hazards and inhibitor protection in the seawater injection system on the Baltic sea rig

Corrosion of carbon steel by bacteria from North Sea offshore seawater injection systems: Laboratory investigation

Influence of sulfidogenic bacteria, from a North Sea seawater injection system, on the corrosion of S235JR carbon steel was studied in a flow bioreactor; operating anaerobically for 100days with either inoculated or filtrated seawater. Deposits formed on steel placed in reactors contained magnesium and calcium minerals plus iron sulfide. The dominant biofilm-forming organism was an anaerobic bacterium, genus Caminicella, known to produce hydrogen sulfide and carbon dioxide. Open Circuit Potentials (OCP) of steel in the reactors was, for nearly the entire test duration, in the range −800<E(OCP)/mV (vs. SCE)<−700. Generally, the overall corrosion rate, expressed as 1/(Rp/Ω), was lower in the inoculated seawater though they varied significantly on both reactors. Initial and final corrosion rates were virtually identical, namely initial 1/(Rp/Ω)=2×10−6±5×10−7 and final 1/(Rp/Ω)=1.1×10−5±2.5×10−6. Measured data, including electrochemical noise transients and statistical parameters (0.05<Localized Index<1; −5<Skewness<−5; Kurtosis>45), suggested pitting on steel samples within the inoculated environment. However, the actual degree of corrosion could neither be directly correlated with the electrochemical data and nor with the steel corrosion in the filtrated seawater environment. Further laboratory tests are thought to clarify the noticed apparent discrepancies.

Corrosion of water injection system in Shengli Oil Field

Purpose – The purpose of this paper is to assess the serious corrosion problems of the water injection system on the offshore oil field and to study the type, and effect factors and mechanisms of corrosion on the offshore oil field in order to develop an effective corrosion inhibitor for the sea water injection system.Design/methodology/approach – The corrosion of metal in a water injection system was studied by weight‐loss and electrochemical methods.The effect factors and mechanisms of corrosion on the offshore oil field were proposed from the trend of corrosion.Findings – FeCO3 is the main corrosion product in the water injection system of the Chengdao Offshore Oil Field. The corrosion rate of coupons in sea water injection systems reaches a maximum peak at a temperature of 50‐60°C. The corrosion rate of coupons exposed in all three water samples increased with an increase in the dissolved oxygen concentration. When the mixed ratio of sea water and produced water and well water is 1:3:1 or 1:2:2, the c...

The effect of long-term nitrate treatment on SRB activity, corrosion rate and bacterial community composition in offshore water injection systems

Biogenic production of hydrogen sulphide (H(2)S) is a problem for the oil industry as it leads to corrosion and reservoir souring. Continuous injection of a low nitrate concentration (0.25-0.33 mM) replaced glutaraldehyde as corrosion and souring control at the Veslefrikk and Gullfaks oil field (North Sea) in 1999. The response to nitrate treatment was a rapid reduction in number and activity of sulphate-reducing bacteria (SRB) in the water injection system biofilm at both fields. The present long-term study shows that SRB activity has remained low at < or =0.3 and < or =0.9 microg H(2)S/cm(2)/day at Veslefrikk and Gullfaks respectively, during the 7-8 years with continuous nitrate injection. At Veslefrikk, 16S rRNA gene based community analysis by PCR-DGGE showed that bacteria affiliated to nitrate-reducing sulphide-oxidizing Sulfurimonas (NR-SOB) formed major populations at the injection well head throughout the treatment period. Downstream of deaerator the presence of Sulfurimonas like bacteria was less pronounced, and were no longer observed 40 months into the treatment period. The biofilm community during nitrate treatment was highly diverse and relative stable for long periods of time. At the Gullfaks field, a reduction in corrosion of up to 40% was observed after switch to nitrate treatment. The present study show that nitrate injection may provide a stable long-term inhibition of SRB in sea water injection systems, and that corrosion may be significantly reduced when compared to traditional biocide treatment.

The Forties Field - 20 Years Young

Summary This paper describes how the development of the Forties field has evolved over the past 20 years; the current issues and activities; and the direction for the future. Introduction In October 1970, BP' s semi-submersible drilling rig SeaQuest struck oil in Upper Palaeocene (Tertiary) sandstones of UKCS Block 21/10 (Figure 1). Four appraisal wells were drilled in 1970 and 1971, which delineated a large oil reservoir at a depth of 2135 metres, covering an area of 93 km2. The maximum thickness of the oil-bearing sandstone was estimated at 187 metres. Reserves were calculated to be 1800 mmstb from an oil-in-place of 4600 mmstb, and production was projected to continue until the year 2000. In 1971 Shell/Essodrilled a successful well, 22/6-1, which demonstrated the south-eastern extension of the field into Block 22/6. The field is a four way dip closed anticline which overlies the Forties-Montrose Ridge and is situated close to the junction of the Central, South Viking and Witch Ground Grabens (Figure 2). The reservoir occurs in thick Upper Palaeocene sandstones deposited as a major sand-rich submarine fan sequence. The field is underlain by a large active aquifer. The development plan evolved during 1972-75. The first major oil field development in the North Sea, it comprised four fixed steel drilling/production platforms, installed in Block 21/10 in 1974 and 1975, with a total capacity for108 wells, a production system capable of handling 500 mbd of oil, later increased to 600 mbd, with 100 mbd of produced water, and a sea water injection system with a capacity of 600 mbd. A schematic diagram of the production system is shown in Figure 3. Development drilling began in June 1975 and production started on 12th September 1975. Plateau production of 500 mbd was reached in1978 and lasted until 1981. A fifth platform, smaller and without processing facilities, was added over the south-eastern extension (South East Forties -SEF) during 1985, with production beginning in March 1987. For more detail on the reservoir reasoning behind the original development scheme see Reference1. Forties is currently producing 111 mbd, the field water cut has only recently passed 60% and 90% of the reserves have been produced. Reservoir Management Reservoir performance has been characterised by excellent vertical sweep through clean sands by the underlying, very mobile aquifer, supported by peripheral sea water injection. There are sufficient permeability restrictions between the three parts of the field, namely SEF, the Main Sand and the Charlie Sand, to cause significant pressure differences between them (Figure 4). Other localised isolated regions have been identified in the FD area during recent infill drilling. The management of the reservoir has been based on treating the three regions separately in terms of pressure support requirements. The primary thrust of reservoir management, common to all areas, has been to track the movement of water within the field to maximise vertical and areal sweep. This has been achieved by performing water shut-off when advantageous to oil flow rate, applying artificial lift when possible, and targeting infill wells at poorly swept areas. With the onset of sea water breakthrough in production wells, bariumsulphate scale deposition has increased in down-hole tubulars and surface facilities (Reference 2). Extended life scale inhibitor squeeze treatments into the formation have been required to inhibit scale deposition. Calcium carbonatescale has also been a problem in gas lifted wells. Generally the deposition of scale is inhibited, but in some cases inhibitor deployment has not been successful. Acid (for carbonate) or chelator treatments have had limited success, while in severe cases wells have been successfully restored to production by milling with coiled tubing (Reference 3).

Detection ofDesulfobacter in oil field environments by non-radioactive DNA probes

Acetate-utilizing, sulfate-reducing bacteria of the genusDesulfobacter were enriched from an oilfield seawater-injection system. These bacteria were detected in enrichment culture and verified asDesulfobacter by an oligonucleotide DNA probe that targets aDesulfobacter-specific sequence of ribosomal RNA. TheseDesulfobacter produced extensive biofilm in culture and exhibited high levels of hydrogenase activity, which suggests a sessile habit and a role in the cathodic depolarization mechanism of microbially influenced corrosion. Phospholipid analyses indicated that one of the oilfield isolates ofDesulfobacter lacked the fatty acid 10 Me 16:0, which has been used as a biomarker for this genus. Desulfobacter were infrequently encountered in the oilfield systems studied, and they constituted a small portion of the total microflora at any sampling location.

A Weight- and Space-Saving Seawater-lnjection System Design

Summary This paper describes an integrated and compact seawater-injection system built around backwashable cartridge filters and catalytic deoxygenation. Suspended solids are removed by a high-efficiency cartridge filter in which the cartridges are regenerated by a proprietary acid rinse. Dissolved oxygen is removed in a single stage to a level of 20 ppb by use of dissolved hydrogen over a palladium catalyst. A combined-cycle power plant makes the unit self-contained. A unit for treating 150, 000 B/D [23 850 m3/d] of seawater is estimated to weigh 260 metric tons [260 Mg] (operating), or about 35% of a comparable "conventional" system using media filters and vacuum deaeration. Space requirements are reduced proportionally.

Water Quality Considerations in Malaysia's First Waterflood

Malaysia's first waterflood, a seawater injection system, was placed in service in the Tapis field in 1982. This paper outlines the design basis and describes the system. Then water quality during and after startup and the formulation of a water quality guide using Millipore membrane filtration tests are discussed. The experience gained and data presented can be applied to current and future waterfloods.

Monitoring Microbial Corrosion in Large Oilfield Water Systems

Summary Monitoring of microbial corrosion is always difficult because of the sessile nature of bacteria and the lack of meaningful correlation between routine bacteria counts and bacterial activity. This problem is further aggravated in a large oilfield water system because of size and sampling difficulties. This paper discusses some monitoring techniques currently used in the oil industry, their limitations, and possible areas for improvement. These improved techniques are in use or will be implemented in the Aramco systems. Introduction Microbial corrosion has caused some failures in seawater injection systems. Whether or not microbial corrosion represents a major corrosion mechanism in the oilfield water system is a controversial question. However, it has certainly become a major concern in recent years. There are two approaches in dealing with microbial corrosion problems in a large oilfield water system. One approach is to start treating the system with bactericide in conjunction with regular scraping when the system is commissioned. The other is to treat the system only when an impending microbial-related problem is clearly defined. in either case, monitoring of microbial corrosion is essential. The first approach is more or less a precautionary measure. The treatment and selection of bactericides is usually based on past experience and laboratory evaluation tests. While the treatment is being implemented, a reliable monitoring program could assess the effectiveness of the current program of microbial corrosion control. In the second case, monitoring of microbial corrosion is even more important. it would provide timely information toward implementation of a treatment program before the system could get out of control. The industry's awareness of microbial corrosion has been indicated by the number of papers published in recent years on this subject. These articles cover a wide spectrum of interest from fundamental corrosion mechanisms to case studies, detection methods, control measures, etc. Although it is not clear to what extent microorganisms are responsible for the observed field corrosion failures, the general consensus still favors early establishment of a routine microbial corrosion monitoring program. The best approach seems to he the establishment of solid baseline data for the system after which any significant future deviation can be interpreted as a sign of a potential problem. The following sections describe the current methods used for routine monitoring, specifically for Aramco's large oilfield water systems. The limitations of these methods, the difficulties encountered, and some suggested studies for modification and improvement are discussed also. Current Monitoring Methods The methods currently used by Aramco can be categorized as (l) cell counts in water, (2) metal surface examination, (3) scraping solids analysis, (4) water quality analysis, and (5) evaluation of current bactericide treatment. Cell Counts in Water. These are used to detect bacterial organisms and their concentrations. it is recognized that confirmation of free-flowing bacteria in the water does not automatically mean trouble. However, if bacteria counts demonstrate a definite increase across the system, or over a period of time, the odds are that bacteria are active and working on the metal somewhere in the system. Cell counts routinely monitored include sulfate-reducing bacteria (SRB), general aerobic bacteria (OAB), iron bacteria, and others. SRB are widely recognized to he primarily responsible for bacteria-induced corrosion in an anaerobic environment. Depending on the nature of the sample to be tested and the types of problems encountered (or expected) in the field, one or several different enumeration techniques are employed. For field work, the method generally used by Aramco is culturing of samples in liquid growth media specifically designed for detecting a certain group of organisms. These laboratory media are prepared using the appropriate field water as a base, with addition of general growth nutrients for the organisms. The use of field water to prepare the media provides a water composition similar to that in which the bacteria originated. The media are supplemented with other ingredients to create an environment conducive to growth of certain bacteria (e.g., certain reducing agents have to he added into the SRB media). The media then are dispensed into serum vials at exactly 9 mL [9 cm3] each and sealed with rubber stoppers and aluminum seals. JPT P. 1171

GUPCO'S Experience in Treating Gulf of Suez Seawater for Waterflooding the El Morgan Oil Field

Summary Pressure maintenance by waterflooding in some reservoirs may be considered essential for satisfactory oil recovery. The main objective of waterflooding is to place water into a rock formation at both the desired rate and pressure with minimal expense and trouble. This objective, however, cannot be achieved unless this water has certain characteristics. The water, therefore, should be treated and conditioned before injection. This treatment should solve problems associated with the individual injection waters, including suspended matter. corrosivity of water scale deposition, and microbiological fouling and corrosion. Gulf of Suez Petroleum Co. (GUPCO) is waterflooding two fields, El Morgan and July, with Gulf of Suez (GOS) water. The paper addresses the treatment phases adopted to improve seawater quality before injection, and to control problems associated with untreated seawater. Also discussed are GUPCO'S experience in seawaterfloods, problems encountered, and corrective actions taken to overcome these problems. The chemical treatment programs adopted are presented along with final conclusions and recommendations that can be applied to similar floods in Egypt with GOS. Introduction Any treatment should be designed to solve the problems associated with individual injection waters. These problems involve suspended matters in the water, corrosivity. scale deposition, and microbiological fouling and corrosion. Additional problems that may result from water injection are injection well plugging and scale deposition both downhole in the oil producers and at surface in production equipment because of incompatible water mixing. Historically, in injection projects subsurface and/or makeup waters, river waters, and lake waters have been used. Seawater also has been used in many waterfloods. Pacific Ocean water, North Sea water, and Gulf of Mexico water have been used in similar waterflooding projects. ADMA has one seawater injection project in Abu Dhabi making use of Arabian Gulf water, which also is used in a large ARAMCO water injection project in Saudi Arabia and in Dubai as well. GUPCO has two injection projects for the El Morgan and July fields involving use of Gulf of Suez water. There is no published information on the characteristics of GOS water the treatment requirement for injection, or GUPCO'S operational experience with these projects. The main purpose of this paper is to introduce some information relative to GUPCO'S seawater injection system for the El Morgan field. Water Injection and Formation Plugging The quality of an injection water depends on its properties-e.g., suspended matter (turbidity caused by organisms and particulates), corrosivity in the system handling this water, and the tendency of the water to deposit scale. Hence the net water quality is dependent on all these properties simultaneously and is primarily connected with its capability to plug the formation rocks. Jones discussed rock plugging by solids. Generally, the tendency of an injection well to become plugged is dependent on the characteristics of both the formation and the injection water. The matrix of any rock is a fine filter for solids in the injection water (free or suspended). This is generally true in spite of differences in pore sizes that formation porous rocks may have. Consequently, the formation face of the water injection well is a good filter for the suspended solids present in the injection water and can become clogged. JPT P. 1449.

Water Quality Aspects of North Sea Injection Water

Summary This paper discusses current water quality assessment methods and some of the parameters that can affect the suitability of North Sea water as an injection fluid. Also included are general comments on the North Sea and its biomass. Examples are drawn from tests carried out during the commissioning of the Forties field seawater injection system in 1976-78. Introduction The use of seawater for subsurface injection is well known in many oil production areas. An area of particular interest at the present time is the North Sea, where the number of offshore seawater injection facilities is increasing rapidly. The high expense of offshore operations plus the high capital cost of the platform very often impose severe constraints on the design engineers, particularly in terms of the size and weight of treatment facilities. An important factor affecting the success of a waterflood project is the quality of the water being injected. Generally, the design basis is such that the water quality should enable injection for the life of the project at a minimum injection pressure and minimum cost. However, very often the quality standards required for injecting a particular water into a particular formation are not known in the early stages of the project. Design Considerations The water quality requirements for successful injection of seawater into North Sea reservoirs is a highly controversial topic at the present time. Water quality is affected by several types of contaminants including suspended solids, scale, oil, bacteria, corrosion products, and marine organisms. Generally, the major water quality problems associated with a seawater flood are due to colloidal iron formation and the presence of organisms. In the past, such problems have been overcome by using other sand or diatomaceous earth filters or by hydraulic fracturing of the formation. However, some operators have experienced problems with the latter approach due to sand influx into the injectors and fracture breakthrough into the producing wells. In an offshore situation, sand or diatomaceous earth filters can be employed only at considerable cost due to their size and weight. In this respect it is essential, therefore, that water quality specifications and designs are adequate but not ultraconservative.North Sea water generally is good quality, containing between 0.2 to 0.8 mg/L suspended solids as determined by membrane filtration techniques. The Forties field seawater injection system has been described previously, and a schematic diagram of the system (capable of handling 150,000 B/D of water) is shown in Fig. 1. Because of the general good quality of water present in the Forties area and weight limitations on the platform, two back-washable cartridge filters are employed. A four-pod filter containing an 80-micron stainless steel element located downstream of the seawater winning pumps provides the first stage of filtration (coarse). A second stage of filtration (fine) is achieved using another filter skid, containing a fiber element, located immediately upstream of the main injection pumps.Initially, there were several problems associated with the fine filters, mainly concerning the backwash and filtration efficiency. To overcome those problems, a considerable development effort was carried out by BP Petroleum Development during 1976–1978. Although that study was aimed primarily at obtaining an efficient backwashable filter element, the data also were employed to investigate present water quality prediction methods. This is of considerable importance as there is very often the need to assess water quality in an unknown environment. JPT P. 1141^

Chemical Treatments Associated With North Sea Projects

This paper discusses carbonate and sulfate formation in the Forties field and some of the laboratory inhibitor-selection techniques used to evaluate scale inhibitors for field use in the Forties injection and production systems. Two chemical treatments for stimulation injection wells also are described. Introduction Pressure maintenance in the Forties field began in Dec. 1976. Initial water sampling and core injectivity studies indicated that seawater would be a satisfactory injection fluid.Before commencing injection, the chemical treatment requirements for the seawater injection system were determined. The principal requirement at that time was for an effective microbiological treatment. This was discussed in detail in an earlier publication. Since that time the need has arisen for injection of suitable scale inhibitors into both the injection and production systems to prevent calcium carbonate and barium sulfate scale formation. This paper discusses scale formation in the Forties field and some of the scale-inhibitor selection techniques used. In particular, a novel test method is described that is used to monitor inhibition and flow pattern influence on formation scaling.The water quality aspects of North Sea injection water have been discussed in detail previously. In that study numerous core injectivity measurements were carried out, and the major core plugging mechanism was attributed to the organic portion of seawater. Although no similar plugging has been detected downhole, BP Research has developed a suitable well treatment product to remove organic debris. Some of the results of this study are discussed in relation to potential field application. Field Scale Problems Scale problems occurring in the Forties field can be attributed to two major factors:commingling of Forties formation and injection waters andprecipitation of calcium carbonate scale from formation water due to variations in pressure and temperature in production systems. A partial chemical analysis of Forties formation water and North Sea injection water is given in Table 1. It will be seen that the commingling of formation water and seawater can precipitate both barium and strontium sulfates, which probably are the worst types of scale found in oilfield situations. The solubility of barium sulfate has been calculated as a function of temperature and mixing composition. The results are shown in Fig. 1 and are presented as a stability index, which is the logarithm of the ratio of actual barium sulfate present to the barium solubility under the specified conditions. For example, a stability index of +0.3 indicates the actual barium sulfate present exceeds the solubility limit by a factor of 2 (10 (0.3)).The worst condition exists for relatively large amounts of formation water and small amounts of injection water. JPT P. 904＾

The Forties Field Sea-Water Injection System

This paper summarizes the design, commissioning, and initial operation of an offshore seawater injection plan in the Forties field of the North Sea. Water sampling and core injectivity, studies are discussed in relation to the subsequent design of surface facilities. Typical results obtained with the system are described in terms of both surface and reservoir requirements. Introduction Pressure maintenance in the Forties field reservoir is Pressure maintenance in the Forties field reservoir is considered essential for satisfactory oil recovery. Initial water sampling and core injectivity studies indicated that sea water would be a satisfactory injection fluid. Based on these studies, surface facilities were designed to prevent the buildup of crustacea, to remove oxygen, to filter prevent the buildup of crustacea, to remove oxygen, to filter solids, and for high pressure injection at rates of about 150,000 B/D per platform. Before beginning injection, the chemical treatment requirements for the sea-water injection system were determined. The principal requirement was an effective microbiological treatment. While corrosion and scale control is not a significant problem now, the use of oxygen scavengers, scale and corrosion inhibitors, and iron chelating agents also are discussed. The quality of water required for successful injection into the Forties reservoir was investigated at length. Typical results obtained with the injection system are presented in relation to core injectivity studies, injection data, and the type of well completion used. Water Sampling and Feasibility Studies Water sampling studies were conducted on North Sea water during 1972 by BP Petroleum Development, Ltd., research personnel. Tests were performed using both discrete and continuous sampling methods to determine the average water quality of North Sea water. Fig. 1 shows typical results of the suspended solids (retained on a 0.8 mu Millipore filter) as a function of sampling depth. Generally, the suspended content is at a minimum near 150 to 200 ft. Although not shown in Fig. 1, the suspended solids content of sea water was greatest during the summer. This might result from the higher levels of organic matter in sea water during the summer. Chemical and bacterial analyses of the samples were as expected for sea water. Feasibility studies to establish the efficiency of the Plenty and Sons backwashing filter for removing Plenty and Sons backwashing filter for removing suspended matter from North Sea water were performed on BP's exploration rig Sea Quest at the end of 1972. During these tests, various filter elements and polyelectrolyte filter aids also were investigated. Particle-size distribution data from these short-term tests indicated that a reduction of about 60 to 70 percent of particles above 3 mu could be obtained with the Plenty filter. Adding polyelectrolyte appeared to have little effect on filter polyelectrolyte appeared to have little effect on filter performance, except at extremely high concentrations. performance, except at extremely high concentrations. The chlorine demand for sea water also was investigated during these trials and was found to be quite low (about 0.3 ppm). Laboratory core studies using North Sea water and Forties reservoir rock have shown that hydration of clays is not a problem. In addition, capillary pressure data indicated that the effective hydraulic pore-throat diameter of the Forties aquifer is about 15 mu. No significant permeability reduction resulting from perforation permeability reduction resulting from perforation plugging should occur if the injection water is filtered to 5 mu. plugging should occur if the injection water is filtered to 5 mu. JPT P. 877

Sea-Water and Subsurface-Water Injection In West Delta Block 73 Waterflood Operations

Experience with sea-water injection in an offshore Louisiana waterflood is presented and compared with the use of subsurface formation water. presented and compared with the use of subsurface formation water. Subsurface water proved to be highly satisfactory in this waterflood. Introduction The West Delta Block 73 field is located 27 miles south-east of Grand Isle, La., and 17 miles west of the mouth of the Mississippi River's Southwest Pass. Water depth is 175 ft. The field was discovered in 1962 and developed during 1963-66. At the end of 1975, cumulative oil production was 128 million bbl and daily rate was 19,600 production was 128 million bbl and daily rate was 19,600 BOPD. Waterflood operations were initiated in 1967 at three small West Delta 73 waterflood plants using filtered and deaerated Gulf of Mexico water. There were no conductors available to drill source-water wells and economic incentive existed for using sea water if feasible. Waterflood planning was based on satisfactory injection at a small waterflood in another offshore field plus analysis of core and water samples from West Delta 73 wells. By 1969, injectivity problems required higher injection pressures. Also, allowable increases that necessitated greater injection capacity resulted in installation of enlarged waterflood plants on four platforms in West Delta 73. Consistently satisfactory injection water was not obtained, and a 1972 study resulted in changing from sea water to a higher-salinity subsurface water. This paper presents the data supporting the change to subsurface water and summarizes 1974-75 experience and costs resulting from the change. Waterflood System Implementation History The West Delta Block 73 field is a low-dip anticlinal structure containing 12 oil reservoirs overlying each other between 8,000 and 9,500 ft with no significant faulting. Shaly intervals are interspersed throughout most reservoirs. Porosity averages 26 percent and typical permeabilities to air are 500 to 800 md in sand members. permeabilities to air are 500 to 800 md in sand members. Early in its life, declining reservoir pressures signaled the need for pressure maintenance, and water injection began in July 1967. As shown by Fig. 1, injection rate was low until an expansion project was completed in 1970. Mechanical problems with injection pumps hampered injection rates problems with injection pumps hampered injection rates during late 1970; as these problems were solved and injection increased, injectivity problems began to dominate. Fifty workovers were completed in 1971 alone in an effort to sustain satisfactory injection rates, but sharp declines rapidly erased much of the initial increases. Sea-Water Treating System The sea-water system at West Delta 73 actually consisted of four separate systems on different platforms. Fig. 2 is a flow schematic of a typical sea-water injection system. Sea water is lifted from -20 ft with a shaft-driven turbine pump powered by a gas engine or electric motor. pump powered by a gas engine or electric motor. Chlorine is injected into the sea water for bacteria control and a polyelectrolyte solution is added for solids flocculation before entering the primary filters. For this service, upflow-type filters are preferred from size-capacity considerations. A second sea-water lift pump is used to backwash the filters. JPT P. 623

The Bay Marchand Pressure Maintenance Project Unique Challenges of an Offshore, Sea-Water Injection System

The Bay Marchand Pressure Maintenance Project Unique Challenges of an Offshore, Project Unique Challenges of an Offshore, Sea-Water Injection System Extreme formation damage caused by the injection fluid; reservoir sands that broke down under injection; severe corrosion; and mechanical problems all spelled trouble in this large pressure maintenance project. Changes, based on test results, have turned it into a successful sea-water injection system. Introduction In the Bay Marchand Pressure Maintenance Project, one of the largest offshore injection systems in the U.S., sea water is injected at high pressures into deep Miocene sands. The need for pressure maintenance in this field off the coast of Louisiana was first recognized in the early 1960's. Six major reservoirs on the prolific east flank of this large salt-dome field exhibited only limited natural water influx after a period of rapid initial development. The early design of the injection system indicated large basic requirements. Injection volume exceeded 50,000 BWPD and injection pressures were anticipated to be as high as 3,650 psig. The injection wells were 11,000 to 12,000 ft deep. A series of unexpected problems developed soon after pressure maintenance began in 1963. First, reservoir sands, which had been sufficiently competent during the early production life of the field, broke down under injection. production life of the field, broke down under injection. In addition, corrosion and the pronounced pressure-rate effects on down-hole equipment were more pressure-rate effects on down-hole equipment were more severe than had been anticipated. Finally, there was severe formation damage, which later was found to be related directly to the use of sea water as an injection fluid. Description of Reservoirs The six major reservoirs under injection in Bay Marchand represent typical Miocene sand development along the flanks of a piercement-type salt dome (Fig. 1). The reservoirs overlie each other at depths between 8,300 ft subsea and 11,400 ft subsea. They are on the east flank of the structure and have an area ranging from 1,300 to 2,300 acres. Structural dip ranges from 24 degrees near the salt dome to 8 degrees at the original oil-water contact. Average net sand thicknesses range from 6 to 36 ft. Initial reservoir pressures varied from 4,600 to 5,291 psig. All but one reservoir were undersaturated initially. Reservoir temperatures vary from 182 to 197F. While initial GOR's averaged 450 scf/STB, oil gravities were between 21 and 30 degrees API. Since PVT properties varied with depth, small primary gas caps PVT properties varied with depth, small primary gas caps existed and the oil columns were undersaturated at their volumetric midpoints. Oil viscosities ranged from 1.1 to 1.9 cp, indicating favorable mobility ratios. Porosities were uniform and averaged 29 percent. However, permeabilities exhibited wide variations; three reservoirs had geometric-mean air permeabilities of less than 100 md, while the remaining sands had values up to 2,000 md. Initial water saturations exhibited a corresponding variation from 40 to 15 percent. percent. Drilling and Production History Initial development of the project sands began in Sept., 1958, with the completion of S. L. 1424 OCS-0387 S-9. Fig. 1 illustrates placement of the completions in a typical project reservoir. The U, W, X, BB and AA structures are 12-well units. JPT P. 389