Well performance management is a critical aspect of production system optimisation in an oil and gas field. Accurately defining the well operating envelope will not only ensure asset integrity, but will also ensure realistic production performance expectations (forecasts) from available well resource. This paper discusses an approach to defining well operating envelopes that incorporates the technical limits and constraints of the various components of the producing well (i.e. reservoirs, sand face completions, tubing erosion and surface production facility, etc.). The methodology employs a visualization tool to graphically represent the operating envelope for the wells based on these constraints. This approach has been implemented in several fields and wells in Shell Nigeria with varying completion types and field-wide constraints. It has also been proven to be flexible enough to accommodate the possible variations between well types and field peculiarities. The case study of five fields in SPDC Swamp West Asset presented in this paper will demonstrate this flexibility. Some of the benefits realized include improved reservoir management and water cut control. Furthermore, the visualization tool has been used to carry out exception based well surveillance that has proven to improve our response time to well deviations for better deferment management.

Reservoir quality in terms of Net-to-Gross (NTG) remains one of the critical components in determining the Hydrocarbon-initially-In-Place (HCIIP), recoverable reserves and production rates of any producing field. Often times, fluvial channel and shoreface deposits are credited to have very good reservoir qualities, hence are choice candidates for completions post-drill of the well. In addition, examples exist of heterolithic sands from which considerable reserves have been recovered during the life-cycle production of the Cream Field in the Niger Delta basin, Nigeria. Improved production from these reservoirs is associated with optimization of well designs. Heterolithic deposits are made up of interbedded sand and mud/shale. These deposits are typically laid down in environments like the tide dominated deltaic and estuarine environments as found in the Niger Delta of Nigeria.The Heterolithic sands found in the field to be discussed are mainly lower shoreface sands with lesser transgressive sand units; lower energy, variably sorted sandstones which are typically finely laminated and commonly intensely bioturbated. There is a continuous transition between heterolithic and shoreface sands. Reservoir quality tends to increase upwards as the heterolithic sands grade into shoreface sands.The sands have poor Kv/Kh values due to presence of shale laminates within the sand deposits. This exacerbates the poor sweep efficiency of the oil with high possibility of by-passed oil. The overall impact of these challenges is low recovery factors assigned to the sands.Due to the properties and nature of the heterolithic sands mentioned above, there is usually low pressure support due to poor aquifer connectivity as a result of the depositional environment, thus triggering a depletion drive mechanism.Interestingly, some of these heterolithics hold considerable recoverable volume that makes the exploitation of such reserves important. Such is the case offshore Norway, Alaska, Canada, Venezuela, Russia, Nigeria and indeed world-wide. As a result, production optimization therefore becomes critical to maximize recovery from wells completed on this facie type.The paper reviews the occurrence of this heterolithics in a field in the Niger Delta, the challenges faced with the current completion strategy and the reservoir management practices. A major challenge as observed in conventional crestal completion on the structure is early gas breakthrough from secondary gas cap formation. Methods of enhancing recovery from heterolithics using improved completion strategy and the requisite reservoir management practices are set forth in the body of the paper.Completion strategies like horizontal wells targeted at the good quality sands has shown an additional potential 1300bopd (seen in the performance of the only horizontal well in the field) as compared to performance of conventional wells, simulation study of water injection and gaslift has also indicated an increase in reserves by 10MMstb.

There are quantum literatures, technical papers, etc on water management in the oil and gas industry. It is a very wide issue and with significant interest due to cost and environmental implications. The focus of this paper is water management in relation to oil production with the purpose of given the industry professional an all-round understanding of life cycle water management. Since by nature the oil is layered above water and the most common reservoirs drive mechanism is underlying aquifer (water), water production is therefore inherent in exploitation of oil. The impact of water in oil production could be good, bad or even ugly. This paper will discuss the various water management techniques from the drilling phase, through completion, production, transportation and treatment at processing facilities. Though basic, this is substantially fundamental. An improper management during any of the phases could prove very costly down the road to the promised developed ultimate recovery for a well completion and even overall recovery from the reservoir. With water production, comes the associated cost of water processing and disposal. It is the view in this paper, that practices and technology should be deployed to delay and minimise water production where appropriate. In today's lower oil prices for longer world, the industry must always strive to reduce their UOC (Unit Operating Costs) to remain profitable and competitive. There are published estimates of water handling costs being as high as 50 cents per barrel of water produced. Reduction in this cost will surely impact the operating company bottom-line. Though there are extensive literature that addresses specific challenges with water management in discrete phases of operation, this paper will attempt to provide a life cycle view, hence its uniqueness. It also highlights practical solutions that are tried and tested.

This paper describes sand cleanout / acidizing operations of four horizontal pre-drilled liner completions in the UU field, offshore Nigeria. These wells were drilled and completed concurrently with similar completions in 1996. Production from the wells declined after four years. The wells were studied using production history curve analysis and nodal analysis techniques. Analysis indicated that the most probable cause of the decline in productivity was plugging of the completion with solids/deposits. Detailed analysis and flow testing were carried out on the available core samples from an analogue well to determine the mineralogy of the possible plugging solids and the most effective treatment recipe to be used to remove the plugging materials. Based on the results of the core analysis, sand cleanout /acid stimulation operations were executed on the subject wells, using coil tubing and specialized coil tubing tools. The operation resulted in a 300% increase in productivity, and was both a technical and economic success. Introduction The primary objective of the stimulation program was to increase the productivity of the wells on the six-well platform known as UU G. Among the six wells on this platform, two of the wells were selected as re-drill candidates. The other remaining four wells were identified as stimulation candidates. These four wells were suspected to be plugged with fines, organic materials and possibly scales. Detailed core analysis, which included X-ray diffraction analysis, scanning electron microscopy, flow testing of the core sample with various BJ acid recipes and effluent analysis by ICP cation concentration determination, was carried out on a core sample from an analogue well. Results of this analysis suggested the possible plugging material and the effective acid recipe to be used to clean out and stimulate the horizontal section of the subject wells. The acidizing operation was designed to be preceded by a sand wash procedure, whereby a switchable jetting nozzle was used to remove sediments from the horizontal drainhole section. Flow tests carried out on the core samples indicated that the fines plugging the pre-drilled liner / reservoir could be removed by pumping a retarded HF acid system. The treatment train also included a fine stabilization additive, in a bid to prolong the effectiveness of the acid operation. The acid was placed in a controlled circulation flowing mode in order to minimize stimulation of the water zones/leg and maximize stimulation of the plugged zone. A Coil Tubing deployed rotating jetting nozzle was used for purposes of mechanical diversion and optimization of the jet impact force. The four wells selected for stimulation were completed with 4.5" predrilled liner across the drain section. In two of the completions, the tubing was stabbed directly into the PBR of the liner hanger/packer at the top of the predrilled liner, while for the other two wells, a packer was run with the tubing set at about 50ft from the top of the liner packer. This left a gap between the end of tubing and the top of the liner hanger.

Matrix acid stimulation as a production enhancement solution has had extensive application in the oil industry. However, not a high percentage of jobs come with outstanding success. In the application being discussed, the well had been stimulated twice with mixed result. While the first job was successful, the second job was not as successful. The well production had declined to as low as 148 bopd and had to be closed in for poor productivity. An analysis of production data and build up survey data confirmed well is an acid stimulation candidate. The well was then acidised with fit-for-purpose treatment recipe. Careful execution according to design yielded 7-fold production increase in the damaged, high gas-oil ratio well. The gain from the acidizing has been sustained in comparison with immediate past acidizing intervention with significant post-job oil decline. The success of the job saved about $4–5 million, being the estimated cost for workover of the well or a new well to drain the remaining reserves. The paper is based on the result as seen in this particular well but is expected that the learning can be further employed in other wells with similar diagnostics. Background The well was drilled in 1972 into a reservoir with a considerable gas cap. The initial completion suffered from high gas production, which led to its closure after about 4 years onstream. It was re-entered in 1979 to move the perforations lower and thus reduce the gas cusping tendency. Production after workover was below expectation and 3 months later the well quit. Productivity Index (PI) after workover was estimated to be about 0.1 bbl/d/psi and compared with 6.3 bbl/d/psi in another well on the same reservoir, impairment was suspected. The interval was then stimulated in 1992 to restore production. With increased production, a noticeable increase in the sand production resulted and this is suspected to be the cause of observed flowline leaks. The sand production was remedied by bean down on the well to restrict production. However production stopped about 12 months after the choke reduction. It was suspected that the flow stopped due to sand accumulation in the wellbore. A coiled tubing sand cleanout with acid stimulation was done again in 1996 to restore production. However the gain of the intervention was diminished with rapid oil decline and geometric increase in the gas-oil ratio. Four years after, oil production had declined to 148 bopd with a GOR (gas-oil ratio) in excess of 20,000 scf/bbl. Due to the excessive gas production and low oil, the interval was closed in from 2001 to 2004. The stimulation intervention being discussed was done in 2004. The interval is also the only producing drainage point on the reservoir.