Poynton, Neil (Baker Hughes Inc.) | Molliet, Annabelle (Baker Hughes Inc.) | Leontieff, Andre (Baker Hughes Inc.) | Cook, Stuart Edward (Baker Hughes Inc.) | Toivonen, Susanna (Kemira) | Griffin, Rick (Kemira Chemicals Inc)
Effective monitoring of scale inhibitor residuals following a downhole squeeze can present challenges due a variety of reasons including contamination of the produced fluid with a topside scale inhibitor, and in the case of subsea wells, often the production is commingled as several wells flow through a single riser. The introduction of phosphorus-tagged scale inhibitors has partially solved the detection issue, but more tags are still needed for subsea developments in the North Sea and for use in commingled production. Detection limits and turnaround time of the sample analysis are also concerns. A new tagged scale inhibitor has been developed combining the proven performance of sulphonated co-polymers coupled with fluorescence technology, thus allowing the scale inhibitor to be detected using fluorescence spectroscopy.
This paper discusses the development of the technology for use in a North Sea field located 130 miles northeast of Aberdeen that has a downhole barium sulphate scaling risk. It is comprised of platform wells and subsea wells that tie back to the host platform via two shared risers. The operator was experiencing difficulties in detecting the subsea squeeze returns so this new tagged scale inhibitor was introduced in one of the wells to improve the monitoring of the squeeze returns. The scale inhibitor was detected successfully in the produced water samples by spectrofluorimetry and validated with gel permeation chromatography. The ultimate goal is to analyse residual squeeze inhibitors using a portable fluorimeter for onsite detection, enabling real-time monitoring of the squeeze returns.
The development of the chemistry and detection monitoring technique and the preliminary results from the field trial, and demonstrates the validity of the analysis method is discussed. This new chemistry, being detectable in mixed fluids, reduces the need for shutting in wells or well tests for sampling, thus minimising process instability due to re-routing wells and shut-in losses.
This paper will highlight the effectiveness of a novel, environmentally friendly multifunctional polymeric scale inhibitor that inhibits carbonate and sulfate scales as well as halite.
The deposition of halite in the oilfield can present a challenge for operators in fields with high TDS brines. The large amounts of halite that can deposit in a short amount of time can lead to reduced production as well as a costly and logistically cumbersome remediation. A customer was controlling halite deposition by injecting a low salinity water source to dilute/dissolve the deposits. However, this remedial solution also presented an additional problem to the customer as the injection of the fresh water source led to calcium carbonate deposition due to brine incompatibility.
This paper will present laboratory test results which highlight the effectiveness of this novel multifunctional scale inhibitor against halite, carbonate and sulfate scales. These results will be compared to traditional scale inhibitors. Following laboratory testing, this environmentally acceptable scale inhibitor product was deployed in high TDS wells where halite deposition was occurring. This paper will also demonstrate the successful implementation of the product, which provided calcium carbonate inhibition and a reduction in the volume of fresh water needed for control of halite deposition. This reduction in water consumption led to significant cost savings for the customer.
The value this case study brings to the industry is an overview of the challenges halite and associated scales present to hydrocarbon recovery and the development/implementation of a multifunctional molecule rather than a chemical blend for scale control. Results of this paper have implications for other fields across the world where halite scale is a flow assurance challenge.
Economical field development strategy often implies tie-in of subsea satellite fields to nearby host installations. This leads to a whole new set of benefits and challenges considering design and material selection, production volumes and limitations, company strategies, holistic management and multi-disciplinary approaches. Operation of complex systems with multiple fluid streams demands a broader understanding of the chemical processes taking place when different fluids are mixed. Typical challenges include mineral scale and "soft scale?? deposits. To ensure optimum production and provide flow assurance through chemical management, proper monitoring is essential. Guidelines and best practices are even more required if the tie-in to the host includes several operators and service companies.
Over the years, the Statoil operated Oseberg asset has through close cooperation with its chemical supplier M-I SWACO systematically improved the sampling and analysis procedures to strengthen the quality of data used in system monitoring. The supplier needs to have a strong focus on flow assurance related to chemical management and provide a range of onshore and offshore monitoring techniques and tools.
Challenges from the North Sea Oseberg Field Centre installation with subsea tie-ins have been discussed. Laboratory and field data from bottle tests, chemical analysis, preservation techniques and scaling potential simulations are presented. The results have been used to plan for side stream tests, develop guidelines for early identification of flow assurance challenges, sampling and monitoring of complex fluid systems and chemical management to avoid process upsets and production losses.
The injection of seawater into oil bearing reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulphate) to the injection and production wells during such operations has been much studied. The current deepwater subsea developments offshore West Africa, Gulf of Mexico and Brazil have brought into sharp focus the need to manage scale in an effective way.
In recent years there has been some consideration given to deployment of scale inhibitor within the fluids associated with the completion of production wells, prior to the start up of production. Until now, effective scale control in frac packed wells at low water cuts has been achieved with phosphonate-based inhibitors applied as part of the acid perforation wash and overflush stages, prior to the actual frac packing operation itself. The deployment of these inhibitors has proved effective in controlling barium sulphate scale formation during initial seawater production, and eliminating the need to scale squeeze the wells at low water cuts (<10% BS&W). Recent developments allowing inclusion of scale inhibitor in the linear and cross linked gel stages has highlighted the need to be able to model this process effectively, thereby enabling optimal use of the chemical and improved squeeze designs.
This paper outlines simulation work carried out using the Petroleum Experts REVEAL software to assess introduction of scale inhibitor into frac pack operations, and identify the most suitable stage of the well completion process during which to apply the inhibitor, to maximise treatment life. Simulation results and field data from these treatments are compared to demonstrate the opportunity this technique presents, and to highlight the importance of chemical placement and the post stimulation flow regime to squeeze life.
This paper discusses the effect of pH on the static barium sulphate inhibition efficiency (IE) of four scale inhibitors: DETPMP and HMTPMP (both penta-phosphonates), EDTMPA (a tetra-phosphonate) and PPCA (a phosphino poly carboxylate). pH is an important parameter with regard to SI functionality. The effect of pH on each SIs IE is explained in terms of SI speciation and binding to Ca2+ and Mg2+ (and possibly Ba2+, Sr2+). In some cases there is an "optimum pH?? for the effective operation of a specific SI, depending on the nature of the functional groups present in the chemical structure.
All static IE experiments were carried out at 95oC and using a North Sea Seawater/Formation Water (NSSW/FW) mixing ratio = 80/20. pH levels of 4.5, 5.5, 6.5 and 7.5 were chosen for testing since this covers the entire range which threshold level SI concentration might normally experience in a reservoir. The IE was determined for each SI at each pH level, where the [SI] was chosen close to the threshold MIC (i.e. pre-2 hour MIC) such that the specific effects of varying pH on 2 and 22 hour IE were clearly visible. In some tests MIC levels were reached, and in these cases, findings are presented in terms of MIC versus pH. For all four species tested, IE versus pH charts are presented. Furthermore, two brine mix compositions (maintaining NSSW/FW = 80/20) were examined, one with [Ca2+] = 742ppm and [Mg2+] = 1242ppm (base case) and one with [Ca2+] = 2000ppm and [Mg2+] = 739ppm (fixed case). The base case [Ca2+] and [Mg2+] result from the normal mixing of NSSW and FW in an 80/20 ratio, molar ratio Ca2+/Mg2+ = 0.36. In the fixed case mix, molar ratio Ca2+/Mg2+ = 1.64. This is done in order to compare and context results within an extensive earlier series of IE results for SIs which were tested in this manner (Shaw et al, 2010a, 2010b).
Figures 1(a)-(d) present the chemical molecular structures of the four SIs tested in this work: DETPMP (1a), HMTPMP (1b), EDTMPA (1c), and PPCA (1d). pH is an important variable as it affects the speciation of weak polyacid molecules, including phosphonic and carboxylic polyacids such as those shown in Figure 1(a)-(d). Figure 2 illustrates the speciation of a simple tri-protic acid, citric acid (H3A), with increasing pH. Clearly, the pH will determine the fraction (%) of each species present in any solution and the same principle applies to all phosphonate and polymeric SIs. If a citric acid solution was titrated with sodium hydroxide, the pH curve obtained would resemble that shown in Figure 3. Citric acid has three relatively similar dissociation constants (Ka), thus instead of three (or at least two) separate end points being detected, a long buffer region is observed, followed by only one marked increase in pH (equivalence point). Similar problems are encountered if a phosphonic acid solution, such as DETPMP (effectively the weak acid, H10A) is titrated with a sodium hydroxide solution, in which case multiple increases in pH are expected on the pH curve. In the case of DETPMP, the various steps in the titration tend to overlap and be much less clear, making such a titration much more problematic to carry out practically. Most of the acid dissociation constants for the commonly used tetra-phosphonate, EDTMPA and penta-phosphonate, DETPMP are known. The speciation chart for EDTMPA is shown in Figure 4, and for DETPMP in Figure 5 (Bull. 53-39(E) ME-3, 1988). Note for DETPMP, Ka1 is estimated; and for EDTMPA, Ka1 and Ka2 are estimated. From Figure 4 for example, it can be deduced that at the standard static IE test pH = 5.5, EDTMPA will speciate into ~30% H5A3-, ~60% H4A4- and ~10% H3A5-. At pH 5.5, DETPMP will speciate into a mix of ~40% H5A5-, ~50% H6A4-, ~5% H7A3- and ~5% H4A6- (Figure 5). Clearly, DETPMP has 10 dissociation constant values because each phosphonic acid functional group contains 2 acidic protons, whereas EDTMPA has 8 dissociation constants (contains 4 phosphonic acid groups, each has 2 acidic protons). Table 1 gives the possible dissociation species for a selection of phosphonate SIs, including the 3 tested in this work.
Al- Mai, Noura (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Baddula, Ravi Chandra (Kuwait Oil Company) | AlAwadi, Mishari A. (KOC) | Bloushi, Taha (Kuwait Oil Company) | Aouchar, Najet (Schlumberger) | Hamed-naji, Iyad (Schlumberger) | Metzger, Thomas (Schlumberger)
Currently, Kuwait Oil Company (KOC) is successfully producing from high pressure and high temperature formations. The reservoirs are deep with True Vertical Depth (TVD) approximating 15,000 feet, and pressures and temperatures of 11,000 psi and 275o F respectively. The formations are composed of carbonates both tight and porous. The produced hydrocarbons are of high H2S and CO2 content, up to 10% and 12%, respectively.
The aforementioned sour environment in addition to water cut occurrence during the production phase have led to scale creation. In addition, corrosion, erosion and pitting also occur, requiring well intervention to sustain production. Furthermore, well monitoring is essential and planning for workover and well interventions is becoming unconventional with higher associated risk.
The recent scale removal activities proved to be very challenging with weight loss seen from the coiled tubing (CT) of approximately 7,000 Ib and CT leakage while operating at the hole condition. The CT pressure control equipment failed due to sudden increased in H2S concentration, which was attributed to the chemical reaction between the cleaning fluid (15% HCl) and the well fluids/scale mixture.
This paper explains the well history, objectives of operation, execution history, procedures and causes of these challenges. Hence, lessons learned, observations and knowledge gained by the Kuwait Oil Company (KOC) are evolving, advancing, and being employed at an accelerated rate despite high cost.
Scale inhibitors are retained within porous media by the two main mechanisms of "adsorption?? (G) and "precipitation?? (?). In previous experimental and modelling work, we have demonstrated for static (equilibrium) "apparent adsorption?? tests where the system exhibits either (a) adsorption only or (b) it is in the coupled adsorption/precipitation (G/?) regime. A complete model of SI retention must have (i) an equilibrium description of the coupled G/? process (Kahrwad et al, 2008); (ii) a kinetic model of coupled G/? which correctly limits to the equilibrium case (i.e. the kinetics must be consistent with the equilibrium G/? model as t -> ¶); (iii) the full kinetic G/? model must then be embedded in a transport model for flow through porous media. Some progress towards this full model has been made and reported previously (Sorbie, 2010; Vazquez et al, 2010).
The full coupled kinetic G/? model is comprehensive and is currently being verified by experiment. However, this full model is quite complex and difficult to understand. Therefore, in this paper, we present a new simple model of kinetic precipitation (?) which explains some key features of this process. This work will present 3 key new findings, as follows:
(i) a very simple mathematical explanation of the mechanism and observations in kinetic precipitation;
(ii) some simple but novel analytical formulae which describe the process;
(iii) a worked field scale radial kinetic precipitation examples is presented which demonstrates how to estimate whether a given field system is close to or far from precipitation/dissolution equilibrium.
This simpler model represents an end-member where a precipitating SI system is described by a solubility (Cs) and a dissolution rate, ?. In most practical cases, some level of adsorption is also superimposed upon this behaviour but this is neglected in this simple model. However, understanding the behaviour of this idealized system does give us some mechanistic insights and some simple practical formula for precipitation squeeze design purposes.
Sulphur compounds are considered as the most hazardous non-hydrocarbons in reservoir fluids, because of their corrosive nature, deleterious effects of petroleum products and tendency to plug porous medium which may impair formation productivity. Precipitation and deposition of elemental sulphur within reservoirs, near well bore region may significantly reduce the inflow performance of sour-gas wells and thus affect economic feasibility negatively.
Studies have sought that almost all deep sour reservoirs precipitate elemental sulphur either occurring as a result of decomposition of H2S to give elemental sulphur or occurring as indigenous usually referred to as native sulphur as a dissolved species. Uncontrollable elemental sulphur induced formation damage has been one of the profit hurting syndromes that occurs in deep water sour gas reservoir.
Meanwhile many correlations have been formulated thermodynamically to predict the occurrences of elemental sulphur but little information related to effect of its saturation on gas production and its corresponding formation damage.
This paper presents an improved model for predicting elemental sulphur saturation and corresponding formation damage around the well bore. Results show that the minimum pore spaces blockage time was over-estimated by previous formulation.
Goodwin, Neil (Scaled Solutions Limited) | Svela, Odd Geir (Statoil ASA) | Olsen, John Helge (Statoil ASA) | Hustad, Britt Marie (Statoil ASA) | Tjomsland, Tore (Statoil ASA) | Graham, Gordon Michael (Scaled Solutions Limited)
Method development of laboratory bench and rig tests for assessing the suitability for application of chemicals via down-hole pressure tube systems is presented. Areas of interest include precipitation or viscosity changes due to solvent loss both in bulk samples and samples in capillaries, and long term product stability in capillaries using new flow rigs designed to more fully replicate pressure tube injection phenomena (particularly chemical stability under extreme T and P conditions). Indeed fluid stability and other challenges relating to down-hole continuous injection have led to a number of failures being recorded in recent years indicating that the physical properties rather than the absolute performance of the chemicals is often key to their successful deployment.
Continuous chemical injection systems for down-hole application are being included in more well completions as their usefulness is recognised. While the initial capital costs are increased, such systems provide a number of benefits over reliance on squeeze treatments for down-hole application. These may include the opportunity to use chemicals unsuitable for squeeze treatment due to the risk of formation damage, the ability to maintain higher doses, and avoiding the need to interrupt production to apply chemicals in complex subsea wells.
Using the developed methods we have identified a number of ways in which formulated scale inhibitors may produce problems within continual injection systems. These include particulate formation and line plugging in capillaries, and solid formation or viscosity increases in response to solvent loss within a tube (as opposed to bulk samples).
These methods will form the basis for future qualification procedures for chemicals intended for down-hole chemical injection with the aim of avoiding application issues in the field. They have been developed both to better understand chemical / fluid stability under down-hole continuous injection conditions following a number of recorded field deployment problems, and then to provide improved qualification for new chemicals and systems.
Addition of scale inhibitor into the reservoir allowing its adsorption and or precipitation into the rock formation and subsequent release during production is one of the most common treatments used in oil field industries to avoid scale formation. Little is known however about the surface chemistry of scale inhibitor interaction with the various mineral phases present in subsea rock formations. This paper presents some recent work investigating these interactions with the spectroscopic techniques commonly employed in surface chemistry. Uptake of NTMP, a model scale inhibitor, by kaolin, halloysite and montmorillonite has been monitored by liquid phase 31P NMR spectroscopy. 31P NMR has also been used to follow the release of scale inhibitor during desorption experiments. The adsorbed inhibitor has been detected directly and quantified with X-ray photoelectron spectroscopy (XPS). XPS combined with argon ion etching has also been able to distinguish between inhibitor adsorbed onto the external surface of the clays and occluded into the interlayer spacing.
The formation of scale as a consequence of the mixture of incompatible brines at severe working conditions is inevitable. Squeeze treatment, as a scale inhibition technique, has been considered a more efficient and cost-effective method of scale inhibition (SI) than continuous or batch injection (Kan et al. 2003; Selle et al. 2003; Pardue 1991; Stamatakis et al. 2006). Batch and continuous methods are mainly used for treating the wellbore and also for adding components of a fracturing fluid (Pardue 1991).
A successful squeeze treatment is determined by the effective lifetime in inhibiting scale in the reservoir system where the inhibitor is released at concentration higher than its minimum inhibition concentration (MIC) (Stamatakis et al. 2006; Bunney et al. 1997; Ramstad et al. 2009; Jordan et al. 2001). The lifetime is dictated by the retention/release mechanisms of the inhibitor in the reservoir (Browning and Fogler 1995). Usually, the efficiency of a squeezed scale inhibitor is controlled by the return curves profile (Sorbie 2010 and Vazquez et al. 2010). The shape of the Scale Inhibitor (SI) return concentration is extremely important in determining the inhibitor performance assuming that the desorbed inhibitor has the same structure as that injected.
Therefore, the success of the squeeze treatment resides in two processes, retention and release of scale inhibitors. While retention allows the scale inhibitor to remain in the rock formation, release permits the scale inhibitor to act against scale formation during longer time. A strong interaction between scale inhibitor and rock formation does not allow its release. But, a weak interaction between scale inhibitor and rock formation may permit its release too fast. There is not complete agreement in the literature about the retention/release mechanistic description in the squeeze treatment (Sorbie 2010).
Retention of Scale Inhibitor
Inhibitor chemicals when injected into rock formations are possibly retained by adsorption and/or precipitation mechanisms as proposed by different studies (Selle et al. 2003; Sorbie 2010; El-Hattab 1985; Sorbie et al. 1993).
Adsorption mechanisms are thought to be influenced by an electrostatic force of attraction or Van der Waals forces between inhibitor molecules and the rock surface (Pardue 1991; Sorbie et al. 1993; Kahrwad et al. 2009; Collins et al. 1999). These interactions are usually described by adsorption isotherms (C) (Sorbie 2010; Sorbie et al. 1993; Kahrwad et al. 2009) which are graphical representations used to describe the scale inhibitor retained onto the mineral surface. Their precise form will characterize the behavior of the scale inhibitor onto the formation.
Precipitation squeeze treatment is based on the formation of insoluble metal-inhibitor complexes, where these particular precipitates are retained in the porous rock formation (Yuan et al. 1993). In other words, the injected inhibitor reacts with divalent cations presents in the rock formation (Browning and Fogler 1995; Pardue 1991; Kokal et al. 1996).