The Tchendo oil field, located 18 miles off the coast of the Republic of Congo has been operated since 1991, by Total E&P Congo in approximately 100 meters of water. The wells are deviated (more than 60 degree), completed with production casing as large as 9 5/8", and partially to extensively perforated, with poor to unknown cement quality. The wells are produced by electrical submersible pumps. One of the three reservoirs, the Sénonien reservoir, is an intercalation of metric carbonate layers with thicker (20 to 30 meters) but poorer quality sandstones. (0.1 to 10 mD). It is shallow (450 mVSS) and depleted (0.37 psi/ft). Various attempts to enhance productivity were tested since initial production, including selective or extensive perforation, acid treatments on carbonate layers, and one open hole horizontal well. However, a large part of the original oil in place still remains in the reservoir. Therefore, it was decided to evaluate the potential of hydraulic fracturing stimulation treatments to rejuvenate the existing wells. The well characteristics made conventional methods of hydraulic fracturing either cost prohibitive or impossible. A first test of the hydrajet propped fracturing technique was performed in 2008, followed in 2010 by two other pilot treatments. This paper details the lessons learned in using this innovative technique to stimulate the three wells and demonstrates limitations of the technique associated with the existing wellbore conditions. This paper will serve as a guide for revitalizing the Tchendo field and possibly other mature oil fields with low to moderate permeability.

fax 01-972-952-9435. AbstractLead and Zinc sulphides have recently become a concern in some HP/HT gas fields.

Lead and Zinc sulphides have recently become a concern in some HP/HT gas fields. The Elgin/Franklin Field (Central Graben North Sea), started production early 2001. The wells produce a condensate-rich gas from the Fulmar and Pentland reservoirs, with initial temperature of 200 degC and pressure of 1100 bar. Mid-2002, the first Calcium Carbonate obstructions appeared downhole on several wells and resulted in a progressive production decrease. Moreover, lead and zinc sulphides were identified on well G6. The heavy scaling from its surface-controlled subsurface safety valve (SCSSV) to the Christmas Tree caused the well to be shut-in from end 2004 until an appropriate programme of remediation and prevention was implemented. Lead and zinc sulphides had not been predicted during the initial scaling studies. While several publications mention these on HP/HT fields, little information is available on downhole inhibitor squeeze. Scale removal lab studies included dissolution of the recovered scales and corrosion tests. A different fluid package was selected for downhole and SCSSV conditions. Scale remediation using downhole acid washes proved efficient by increasing wells production. The upper part of the completion on well G6 was cleared from scales by a coiled tubing operation in mid-2005 and the integrity of the SCSSV was restored. To prepare for scale prevention, a benchmarking of inhibitors from four suppliers was performed in a third party lab over a period of more than two years. Appropriate equipment was put in place and the methodology was optimised. The tests were conducted in anaerobic conditions with thermally aged chemicals. Two scale inhibitor squeezes were deployed, although progress is still to be made for "exotic" scale prevention. This paper presents the Elgin/Franklin scale-control strategy from a thorough fluids selection to the field deployments. Results and optimisation are discussed. Introduction Calcium Carbonate (CaCO3) is the most common "self-scaling" specie found in oil and gas fields. Scale deposition is a widespread problem that causes production deferment, necessitates costly intervention, and can compromise safety systems. The situation can be more severe in high-pressure, high-temperature (HP/HT) fields since the changes in pressure and temperature are potentially greater and because the formation water in such fields is often of very high salinity. Initial scale control philosophy. The Elgin/Franklin Field is a platform development in the Central Graben area of the North Sea's UK sector (Block 22/30b, 22/30c and 29/5b), approximately 240 kilometers East of Aberdeen. Production started in March 2001, from 10 wells. The Fulmar and Pentland reservoirs in Elgin/Franklin produce a retrograde condensate gas and are characterized by very harsh conditions - temperature close to 200°C, initial pressure up to 1100 bar - and a high salinity formation water, close to 300,000 mg/l. The hydrocarbons also contain around 3 mol% CO2, and traces of H2S in insufficient quantity to be measured in produced fluid. The potential for scale deposition - primarily sodium chloride (NaCl) and Calcium Carbonate (CaCO3) - was recognized early in the project phase. Preliminary studies were performed in 1995 and 2000, based on water samples taken during DST in 1991 and 1995. Initial scale prediction studies identified a low risk for calcium carbonate scaling in the upper tubing of wells with less than 100m3 of water per day. Of more initial concern was the NaCl, prone to forming not only in topsides, but also downhole, early in the field life, due to vaporisation of water when in small amount.

Coreflood experiments are an integral part of the selection and optimisation of scale inhibitor treatments, providing information on formation damage, inhibitor return profiles and dynamic retention isotherms. However, significant discrepancies can arise between core and field due to test methodology. In a previous paper (SPE131131), we demonstrated that test methodology can have significant consequences for the comparative inhibitor returns, particularly with respect to oversaturation. The paper showed that many of the limitations can often be overcome through appropriate simulation techniques. We extend this work and present further results of laboratory core flood tests specifically designed to examine the effect of core flood test methodology on the derived return isotherm, particularly examining the effect of injection of different volumes of main treatment ranging from ~ 0.5 pore volume (under saturated) to 20 pore volumes (over saturated) for a series of different generic scale inhibitors. This work clearly identifies the significant detrimental artefact of inhibitor oversaturation. This paper differs from the previous works (SPE 131131) in that examples are shown where core flood oversaturation can not be overcome with effective isotherm derivation and upscaling. This is due to significant differences in the isotherms derived as a function of the level of oversaturation with main treatment chemical. This paper will also demonstrate the impact of low concentrations of impurities and or the use of chemical blends when testing with poorly designed core flood tests. Thus the paper directly addresses the procedures involved in core flooding, recommends approaches and test protocols which allow more appropriate product ranking and allow improved simulation from core to field.

Lead zinc and iron sulphide scales are known to be particular issues with gas production fields, particularly those producing from HP/HT reservoirs. The Elgin/Franklin Field is located 240 kilometres east of Aberdeen in the Central Graben Area of the North Sea, blocks 22/30b, 22/30c and 29/5b. With initial temperatures of 200°C and pressures of 16,000psi this is one of the highest pressure and temperature developments ever undertaken. The fields began production in Q1 2001. Preliminary scaling studies identified a risk for calcium carbonate scaling with an increased scaling risk as the wells mature. In May 2002 the first obstruction occurred and was identified as CaCO3 resulting in a programme of remediation and treatment as discussed previously in SPE 94865. In late 2004 however zinc and lead sulphide scale deposits were also identified. These had not been predicted during the initial scaling studies. This resulted in the well being shut in and the squeeze treatments designed for carbonate scales (see SPE 94865) being delayed to allow further chemical selection. It was recognised however that the prediction of sulphide scale and the methodologies available for their laboratory assessment, especially in brines containing high dissolved iron concentrations, are not as well developed as those for the more conventional sulphate and carbonate scales. This paper therefore focuses on the detailed assessment and methodology development required in order to assess the problem in the Elgin/Franklin Field. Scale prediction identified that the major scales that could be formed were calcium carbonate, iron carbonate, iron sulphide, lead sulphide and zinc sulphide. Given the predicted oversaturation of various minerals, preliminary laboratory tests were conducted in order to ensure that the scale formed was representative of the field scale. This showed that small variations in brine composition can have a relatively significant impact on the type of scale formed in the laboratory tests and more significantly that this did not completely tie up with predictions conducted using commercial thermodynamic models. The paper describes the importance of proper test methodology and describes more sophisticated test protocols and processes for ensuring that the laboratory tests replicate field production conditions. These techniques were then used to select an appropriate chemical for field treatment. Field treatments have now been conducted by downhole "squeeze" application using a treatment package similar to that identified in SPE 94865 and the results from these field treatments are discussed. Details of the developed test methodologies and chemical selection process undertaken for these more exotic scales together with results from the field trial are described. In addition discrepancies between the thermodynamic scale prediction models and the laboratory data are also discussed indicating that further model tuning may be required for these less common scales. Introduction Scale deposition is a widespread problem that causes production deferment, necessitates costly intervention, and can also compromise safety systems. Scaling in gas and gas-condensate fields is mainly induced by the reductions in pressure and temperature inherent throughout the production system, known as self-scaling. In particular, pressure drops cause evaporation of water and/or loss of carbon dioxide from the produced water to the gas phase, which can then lead to progressive supersaturation of carbonate, chloride or (less commonly) sulphate minerals.[1] The situation can be more severe in high-temperature, high-pressure (HTHP) fields because the changes in pressure and temperature can potentially be greater and because the formation water in such fields is often of very high salinity. Moreover, the high temperature promotes faster scale nucleation and growth, and can lead to thermal degradation of chemical inhibitor applied to control scale deposition.[2,3,4] In addition to the conventional carbonate and sulphate scales, less common scales such as the iron, lead and zinc sulphides are also encountered in HT gas production systems with their formation driven by temperature reductions during production. This paper focuses on the problems associated with lead and zinc sulphide mitigation in one such field system, namely the Elgin/Franklin System in the UKCS.